Legislature(2007 - 2008)HOUSE FINANCE 519
10/31/2007 09:00 AM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB2001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB2001 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
October 31, 2007
9:05 a.m.
MEMBERS PRESENT
Representative Carl Gatto, Co-Chair
Representative Craig Johnson, Co-Chair
Representative Anna Fairclough
Representative Bob Roses
Representative Paul Seaton
Representative Peggy Wilson
Representative Bryce Edgmon
Representative David Guttenberg
MEMBERS ABSENT
Representative Scott Kawasaki
OTHER LEGISLATORS PRESENT
Representative John Coghill
Representative Les Gara
COMMITTEE CALENDAR
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."
- HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: HB2001
SHORT TITLE: OIL & GAS TAX AMENDMENTS
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
10/18/07 (H) READ THE FIRST TIME - REFERRALS
10/18/07 (H) O&G, RES, FIN
10/19/07 (H) O&G AT 1:30 PM HOUSE FINANCE 519
10/19/07 (H) Heard & Held
10/19/07 (H) MINUTE(O&G)
10/20/07 (H) O&G AT 12:00 AM HOUSE FINANCE 519
10/20/07 (H) Heard & Held
10/20/07 (H) MINUTE(O&G)
10/21/07 (H) O&G AT 1:00 PM HOUSE FINANCE 519
10/21/07 (H) Heard & Held
10/21/07 (H) MINUTE(O&G)
10/22/07 (H) O&G AT 9:00 AM HOUSE FINANCE 519
10/22/07 (H) Heard & Held
10/22/07 (H) MINUTE(O&G)
10/23/07 (H) O&G AT 9:00 AM HOUSE FINANCE 519
10/23/07 (H) Heard & Held
10/23/07 (H) MINUTE(O&G)
10/24/07 (H) O&G AT 9:00 AM HOUSE FINANCE 519
10/24/07 (H) Heard & Held
10/24/07 (H) MINUTE(O&G)
10/25/07 (H) O&G AT 10:00 AM HOUSE FINANCE 519
10/25/07 (H) Heard & Held
10/25/07 (H) MINUTE(O&G)
10/26/07 (H) O&G AT 10:00 AM HOUSE FINANCE 519
10/26/07 (H) Heard & Held
10/26/07 (H) MINUTE(O&G)
10/27/07 (H) O&G AT 2:00 PM HOUSE FINANCE 519
10/27/07 (H) Heard & Held
10/27/07 (H) MINUTE(O&G)
10/28/07 (H) O&G AT 2:00 PM HOUSE FINANCE 519
10/28/07 (H) Moved CSHB2001(O&G) Out of Committee
10/28/07 (H) MINUTE(O&G)
10/29/07 (H) O&G RPT CS(O&G) NT 4DP 1NR 2AM
10/29/07 (H) DP: SAMUELS, NEUMAN, RAMRAS, OLSON
10/29/07 (H) NR: DOOGAN
10/29/07 (H) AM: KAWASAKI, DAHLSTROM
10/29/07 (H) RES AT 1:00 PM HOUSE FINANCE 519
10/29/07 (H) Heard & Held
10/29/07 (H) MINUTE(RES)
10/30/07 (H) RES AT 9:00 AM HOUSE FINANCE 519
10/30/07 (H) Heard & Held
10/30/07 (H) MINUTE(RES)
10/30/07 (H) RES AT 6:30 PM HOUSE FINANCE 519
10/30/07 (H) Heard & Held
10/30/07 (H) MINUTE(RES)
10/31/07 (H) RES AT 9:00 AM HOUSE FINANCE 519
WITNESS REGISTER
CLAIRE FITZPATRICK, Commercial Senior Vice President
BP Exploration (Alaska) Inc.
Anchorage, Alaska
POSITION STATEMENT: During the hearing of HB 2001, provided a
presentation.
BERNARD HAJNY, Manager
Production Tax & Royalty
BP Exploration (Alaska) Inc.
Anchorage, Alaska
POSITION STATEMENT: During the hearing of HB 2001, answered
questions.
JOHN IVERSEN, Director
Tax Division
Department of Revenue
Anchorage, Alaska
POSITION STATEMENT: During the hearing of HB 2001, provided
comments and answered questions.
KEVIN MITCHELL, Vice President
of Finance and Administration
ConocoPhillips
Anchorage, Alaska
POSITION STATEMENT: During the hearing of HB 2001, provided a
presentation.
JIM TAYLOR, Manager
Production Tax & Royalty
ConocoPhillips
Anchorage, Alaska
POSITION STATEMENT: During the hearing of HB 2001, discussed
future resource development on the North Slope and how the tax
structure will impact that development.
KURT GIBSON, Acting Deputy Director
Division of Oil & Gas
Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: During the hearing of HB 2001, discussed
the exploration incentive credits in AS 43.55.025, enacted in
2003.
JULIE HOULE
Resource Evaluation Section
Division of Oil & Gas
Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: During the hearing of HB 2001, answered
questions.
ACTION NARRATIVE
CO-CHAIR CARL GATTO called the House Resources Standing
Committee meeting to order at 9:05:42 AM. Representatives
Johnson, Guttenberg, Edgmon, Fairclough, Wilson, Seaton, and
Roses were present at the call to order. Also in attendance
were Representatives Coghill and Gara.
HB2001-OIL & GAS TAX AMENDMENTS
9:06:21 AM
CO-CHAIR GATTO announced that the first order of business would
be 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." [Before the committee was CSHB 2001(O&G).]
CO-CHAIR GATTO informed members the presentations today would be
given by the stakeholders. He introduced Claire Fitzpatrick and
Bernard Hanjy.
9:07:02 AM
CLAIRE FITZPATRICK, Commercial Senior Vice President, BP
Exploration (Alaska) Inc., provided the following presentation:
Thank you, Mr. Chairman, members of the committee.
First off, I'd like to thank you for the opportunity
for BP to come and present its perspective and its
concerns and views over the proposed bill. Before we
start, I'd like to introduce myself. My name is
Claire Fitzpatrick. I'm the commercial senior vice
president for BP here in Alaska. With me I have
Bernard Hanjy, who is our tax manager responsible for
production taxes and royalty.
What we're proposing to do this morning is to focus
the discussion around Alaska. We've elected not to
bring in various other independent and expert views,
recognizing that you have heard from many already and
we felt it might be more appropriate to focus on
what's Alaska's resource, Alaska's cost structure.
What are the things that we think are appropriate and
important for you to be taking into consideration as
you're considering what is the right fiscal policy for
Alaska? From our perspective, this is about Alaska's
economic future.
I know that many of you have had various
presentations, both through the last debate and many
of you, I believe, were kind enough to sit through
some of our presentations last week where we went
through a number of operational matters. We are not
proposing to go through the same degree of operational
and technical material this time but rather allow the
conversation to move on a bit more through some of the
specifics around the bill. However, I would like, at
the outset, to make the offer that if there are more
technical things that you would like to have presented
to you, we're very happy to arrange for the most
appropriate people to come down and present them to
you. I may be able to answer some questions but I'm
not an operating expert, therefore my answers may not
be sufficiently detailed to actually meet your
particular requests and requirements.
We'd also like to say that we support the net tax
basis, which is what is currently in petroleum
production profits tax (PPT) and we believe the policy
behind that was around promoting investment. When we
make our investment decisions, we're looking with a
view to both the medium and the long term and
sometimes that can take a little bit of time before
you would actually see what the outcome of those
investments are. But we'll go through that a little
bit more.
The other thing I'd like to say at the outset is our
starting point is not about there will be no
investment if changes are made. We have been in
Alaska for nearly 50 years and we believe that there
will be good business opportunities for us here for
the next 50 years. Changes in fiscal policy do change
investment decisions. They do impact them. It's not
the sole impact but it is one of them. So, for us,
changes in fiscal policy will impact the scale and
pace of investment. We will still continue to do the
investment that we need to do in order to meet our
contractual obligations, which is to prudently develop
the resource. What we're looking to do is to talk
about what ways and things you need to consider when
you're looking at how do you maximize the investment,
attract the investment, both from the likes of BP who
is currently here, but also for companies who are not
yet here that you would like to encourage to come and
invest here.
I think we might have a small technology problem so
we're going to do the more old fashioned way of going
back and forward. Sometimes paper and pen can be
easier ....
We'd like to just start with our key messages and then
we'll go through in a little bit more detail. I think
through the presentations that you've already listened
to, you'll hopefully - and I do believe that you
appreciate that accelerating the decline will outweigh
any benefit that would come through a change in the
tax rate. Increasing the barrels in the pipeline will
increase the opportunity for the state, in terms of
its revenue generating.
9:12:20 AM
CO-CHAIR GATTO asked whether there is a way to increase the
volume of production, or is the task to lessen the decrease in
volume.
9:12:38 AM
MS. FITZPATRICK answered, "Yes to both." She said she will
address how to mitigate the decline and what the opportunities
are within the existing fields. Some of her comments will go
beyond the existing decline and through some of the more
challenged projects. She will also address how to tap into
Alaska's resource base in the existing fields and beyond through
incumbent companies and new explorers. DNR's decline forecast
shows a 1 percent decline, down from the current 6 percent
decline. She asserted it is possible to get below a 1 percent
decline.
MS. FITZPATRICK continued her presentation, as follows:
The key thing for us - I think we have a common goal
of getting more barrels in the pipe, whether that's
through a combination of stemming decline but also
getting more barrels beyond just stemming the decline.
Investment is the key and that's investment both in
technology, that's investment in the infrastructure.
One of the things that is also key to remember is the
North Slope was an amazing engineering feat. It was
built with a view of 25 to 30 years. If we're now
thinking, as at BP, we talk about the next 50 years,
we also need to think about what's the infrastructure
- what's the right infrastructure for the next 50
years. We have to bear that in mind when we're also
thinking about the production because there's a huge
efficiency aspect to take into consideration around
what's the best way to access the next 50 years.
When the bill initially came out, what's now known as
HB or SB 2001 - I know we're now on to committee
substitutes, one of the concerns we raised was around
the fiscal stability and that was around - if there's
another change made this year, this will be the third
change in tax structure in three years. I know there
have been some questions raised about is it the third
or the second. I'm aware that the ELF aggregation was
not done through the legislative body but, for
investors, it was an increase in tax. So this would
be the third change in tax in three years and that
does have a bearing when we're thinking about what is
the fiscal risk around investments that are made.
And, for companies who are not yet in Alaska, they're
watching and they're aware of that as well.
9:15:12 AM
CO-CHAIR GATTO asked how many changes are acceptable to BP
within a specific timeframe.
9:15:23 AM
MS. FITZPATRICK responded that BP does not have a definitive
number, unless the parties are under complete contractual terms
and even those can change. She opined that keeping a fiscal
policy in place for ten years sounds reasonable. She noted one
must recognize that the environment changes so it comes down to
establishing a policy of goals and objectives that is designed
to be flexible enough to respond to changes in the market while
meeting the goals and objectives.
9:16:00 AM
REPRESENTATIVE GUTTENBERG asked Ms. Fitzpatrick to expand on the
definition of stability and whether that refers to the number of
times a tax policy changes or whether those changes are in BP's
favor. He noted that oil companies may come back to the
Legislature after a number of years and say a particular policy
is not working and is preventing development. He questioned
whether tax changes made in such a case would be counted as
[destabilizing] changes. He pointed out that changes in the
social, political and economic climate, and geologic structure
and activity, also precipitate tax changes.
9:16:54 AM
MS. FITZPATRICK relayed that BP bases its investment decisions
on a number of factors: geology, political risk and economic
risk. She said BP does not view North America as politically
unstable but it does view some other countries that way. When
looking at economic risk, BP views price risk, cost risk,
inflation, supply and demand, and fiscal risk. She opined that
instability is meaningful in terms of the number of changes and
the reasons behind them. If BP requested the Legislature to
make changes in royalty relief, she would not consider that to
be a fiscal change because that would remain within the existing
fiscal policy and would address how both parties ensure that
investment useful to both of them progresses. She said
regarding whether the changes are to the producers' advantage,
she is aware of examples around the world in which taxes were
lowered. She suspected taxes have increased in more countries
than decreased. She would count that as a change to fiscal
policy.
MS. FITZPATRICK then continued her presentation:
One of the things which we also raised earlier, and
we're still in a similar place and that is that
raising taxes deteriorates the economics. There isn't
a definitive point at which I can say that's when it
moves from one side of the line to the other, but it
will deteriorate economics and, because fiscal terms
are part of the economics that we take into
consideration, it will have an impact.
Where we are, in terms of BP, we don't explore in the
true sense of the word, what we do is - this is what
we use in our language, is we explore for the known
through technology and that is, there's a large known
resource base and what we would like to do is focus
our efforts on actually developing that rather than
focusing our efforts on finding stuff that isn't yet
out there. I'm hopeful there are many other companies
that are more interested in doing that because I think
both are important for Alaska. The key is basically
around increasing investment.
This is a slide which we've shown before and it's also
one that the state has shown. You'll notice
throughout our presentation where possible we're not
introducing new numbers, new graphs. We might show
them in slightly different ways but that's because the
principles are the same and introducing new numbers
then tends to confuse the issue into where the numbers
are coming from as opposed to the principle that we're
trying to talk about.
This is the decline that is currently projected.
And, getting back to Representative Gatto - Chairman's
question of is this around just stemming decline or
actually moving in the other direction. You'll see
the answer is a little bit of both over a period of
time, depending on which years you're looking at.
We've elected not to show all of the history and
historically the decline has been around 6 percent.
It has been lower in certain years. You'll notice on
the chart the sort of 2001, 2002 times actually is
considerably flatter before it starts to decline
again. That's reflecting the investments that were
made in Alpine and Northstar so that flattening is
actually those two fields coming on-line. That was
the result of increased investment that happened a few
years prior to that as it takes time for these
investments to actually come through as volumes.
What we've actually got on the chart, it's not
terribly clear in the colors up on the screen so I
apologize for that. I hope it's a little clearer on
the slide in front of you. There are basically four
key elements to this. There's the solid green with
the sort of steep decline curve. That's what we refer
to as the underlying production. That's the
production that would come from the existing wells,
provided we do normal and expected maintenance for
that.
There isn't a hard line and that's deliberate between
that, what I'll refer to as a wedge, and the next one
up which is a slightly more dotted one, which again is
more clear on the slide in front of you. That's
reflective of the additional well work, i.e.
maintenance, bringing the wells back to the most
effective production and new wells that we drill.
We've drilled in the last 10 years about 800 wells in
Prudhoe Bay. We drilled - or we've invested, rather,
in 100 new wells across the North Slope last year and
we predict we'll be investing in about 100 this year.
That's across the Slope in our interests, our fields,
in the ones we have investments in.
9:22:54 AM
CO-CHAIR JOHNSON asked for clarification of the total number of
new wells.
9:23:34 AM
MS. FITZPATRICK clarified that 800 new wells have been drilled
in Prudhoe Bay over 10 years. BP, as an interest owner in that
field, is investing in them, as are the other working interest
owners. When she said BP has invested in 100 wells across the
[North] Slope, she was referring to Prudhoe Bay, Kuparuk, and
some of its other fields. She elaborated:
In terms of the 100 wells that we invested in, what
percentage does that reflect of the total wells. I
can see it on a bit of paper and I'm hesitant to give
you the definitive number and, again, add more
confusion. So, if you're okay, I know I have it back
in the office. I will definitely get it for you.
9:24:29 AM
CO-CHAIR JOHNSON expressed interest in knowing what portion of
the drilling is not being done by BP to determine the total
number of new wells, regardless of the investor.
9:25:09 AM
MS. FITZPATRICK said the number she has refers to the percentage
of total wells BP invests in. She said [BP invests in] more
than half and she will provide that information [at a later
date].
9:25:20 AM
CO-CHAIR GATTO asked how many wells are in the Prudhoe Bay Unit.
MS. FITZPATRICK estimated 2,500.
9:25:42 AM
BERNARD HAJNY, Manager, Production Tax & Royalty, BP Exploration
(Alaska) Inc., affirmed that a previous BP testifier said 2,500
wells have been drilled in Prudhoe Bay.
CO-CHAIR GATTO questioned whether a limit on the number of wells
to be drilled exists and how the industry will determine whether
the pace of drilling will continue at its current rate.
9:26:30 AM
MS. FITZPATRICK informed the committee that the pace of drilling
must increase to sustain the current production decline level.
She explained that existing wells lose efficiency as they age
and production declines rapidly. In those cases, BP does "well
work" to improve efficiency. In addition, in terms of the new
wells that get drilled, there is capacity to drill more wells
but BP has a footprint constraint for environmental reasons.
That is where new technology is applied to drill multi-lateral
wells within the same footprint of the existing unit.
9:27:32 AM
CO-CHAIR GATTO questioned whether a vertical well counts as one
or three wells.
9:27:42 AM
MS. FITZPATRICK explained that it is counted as both. There is
one [vertical] bore, but each lateral is counted individually
so, for example, the count would be 1a, 1b, and 1c.
9:27:48 AM
REPRESENTATIVE SEATON pointed out that 100 wells were drilled in
2006 prior to the passage of PPT and 100 wells are being drilled
in 2007 under the PPT. He said the committee must determine the
effect of the change in Alaska's tax regime regarding net
profit, deductibility, and credits on the oil industry's
investments. He asked whether the amount of drilling and well
work has increased since the enactment of PPT.
9:28:47 AM
MS. FITZPATRICK replied that a direct correlation is difficult
to make on an annual basis because BP makes short term and long
term investment decisions. Long term investments will not show
results for maybe five or ten years so no instant impact can be
seen. She said BP is investing to get the barrels in the third
layer up, which will take time. Whether BP would have drilled
more or less wells under a different scenario is hard to say
because her business models and plans are not based on what
might have been in place. BP wants to drill more wells but is
limited by capacity and infrastructure. However, if BP is
confident that the environment it is working in is stable, it
would plan the logistics and support to move forward.
9:30:49 AM
REPRESENTATIVE SEATON recalled testimony given last year by Mr.
Van Tile (ph) of BP during which he said BP had sanctioned all
of the projects that were economic [on the North Slope] and was
proceeding as fast as possible. He asked whether the situation
has changed.
9:31:12 AM
MS. FITZPATRICK replied that the situation is always changing
for a variety of reasons. One reason is that BP might progress
down a path but events change due to a greater understanding of
technical risks. She said much work is done prior to the time
BP will formally sanction projects and commit funds. She
explained that BP's process of sanctioning a project consists of
the group committing funds to progress a project with the
expectation of developing a specific resource. The group does a
lot of work on projects in Alaska before it goes forward to get
a formal commitment from its organization. She noted a lot of
activity is taking place, for example, on the western region
development in Prudhoe Bay. That project will probably cost
more than $2 billion. It has not been formally approved by BP's
board, yet two years of preparation and testing have been done.
The activities so far range from drilling wells to building new
facilities for gas handling, to getting a handle on the
technical, economic and financial risk.
9:33:40 AM
REPRESENTATIVE SEATON asked, "I am wondering whether BP has
economically viable projects that they determined are
economically viable now that they are not investing in, or are
they investing in all of the projects that they determined are
economically viable?"
9:34:24 AM
MS. FITZPATRICK replied that when BP identifies an economically
viable project, it begins to work on how to go about
accomplishing it.
9:34:27 AM
CO-CHAIR GATTO asked if, within BP, teams of employees that
represent viable projects in different parts of the world
compete with each other.
9:35:12 AM
MS. FITZPATRICK said BP makes investment decisions at different
levels of study. Group level decisions are global and strategic
in nature and concern market exposures for various countries,
such as what kind of market exposure does it want in Southeast
Asia versus what kind of country exposure it wants in North
America. If the group makes a strategic decision to enter a new
country, that would not be at the expense of taking funds from
Alaska, for example. That is done under a different set of
principles that guides the group's management of its financial
position. However, project decisions are made under a different
set of principles and criteria; the most important being how
risk will be managed and mitigated. Not all projects get to the
same stage of maturity and have the same robustness at the same
time. She cautioned that even projects that look very, very
good economically may not be approved because the technology
risk is huge. She said regarding whether projects compete
globally, some of that has to do with the desired portfolio
balance. Alaska projects are most likely competing against
other projects in North America.
9:37:24 AM
CO-CHAIR GATTO observed that the success of a project comes down
to the net present value and the likelihood of success.
9:37:45 AM
REPRESENTATIVE WILSON compared this conversation to planning for
retirement and investing accordingly. Younger people make a
variety of riskier investments but, as they get closer to
retirement age, they realize they cannot take those risks. She
said many experts have testified that the major oil fields have
been discovered already. She asked whether BP has stopped
exploring and is instead zeroing in on using new technology to
find the remaining oil in the known fields. She assumes BP
looks at many angles of development.
9:40:28 AM
MS. FITZPATRICK agreed with Representative Wilson's analogy of
risk profiling at different stages and felt it applies from a
global perspective because BP takes different risks in different
places. However, in Alaska, BP feels that exploration
opportunities for other companies exist. BP is focused on
extracting the harder barrels from existing fields. She said it
is likely that the majority of the larger oil fields have been
discovered but BP is always surprised by what geology has to
offer. She noted that global warming may be a mixed blessing in
that the ice caps may change and will provide opportunities for
research. Those areas have not been surveyed to the same extent
as other places. She continued her presentation:
So going back to the chart here in terms of what are
the various things that we need to work on, we've
touched on the drilling, the in-field drilling. I
started to say that I haven't got a hard line between
the first two slices that are up there and that's
because it's very easy to draw it. I've just about
mastered the PowerPoint skills to draw that myself,
but not quite.
In reality, being able to separate them out and be
able to work out partly how the molecules - which
comes from which - what's cause and what's effect if
you drill a pressure injection. That causes benefits
for several wells. How would you attribute it to each
of those particular areas and allocating costs and
things like that? I know it's an area that has come
up in discussion and just wanted to share with you
that the IRS, the federal tax authority attempted to
do one of these sorts of splits in the past with a
windfall profit tax and reverse that decision because
it was impossible for them to actually manage it. It
resulted in a long period of litigation, which was in
nobody's best interest. Both Norway and the UK have
on many an occasion had conversations on how could
they do this. They've never managed to come up with a
way, which is actually workable, without creating a
huge bureaucratic process, which, from the
government's perspective, they didn't want to do.
From the industry perspective, we didn't particularly
want to have to double our staff to manage it either.
So just so you're aware that I can make it look nice
and simple in a graph but unfortunately life doesn't
quite work like that.
Weaving on, then, to the next layer of sort of those
large projects, technology, I'll come along and touch
a bit about what some of those things are. It's
critical, in terms of getting the kind of production
profile that's shown here. Do we believe it's
possible? It is but it will require significant
investment well in excess of what's been seen in the
last 20 years.
Is it worth going for? I think it is but that's
because I believe the right answer for the future of
the economic position here is getting more barrels in
the pipe.
New fields and exploration - we have Oooguruk coming
on, hopefully early next year. I'm sure Pioneer will
be talking to you. They've already done great
testimony and that's great. That's a wonderful sign
to see - someone else on the North Slope developing
one of those smaller fields where they were able to
sort of see value and decided to go for it. That's
great to see and I'd like to see more of that.
You'll also see a little bit of a bump further out
around the 2011-12. I think that's probably Liberty
coming on, which is a field BP is in the process of
starting to develop. That will involve having the
world's largest rig up on the North Slope and drilling
a lateral well, which will be nine miles to actually
bring that across, and we'll be bringing that across
the Endicott facilities. That's a federal lease but
it's still barrels going into the pipeline, which is
still a benefit to Alaska and it's a benefit also in
terms of getting better positions for new entrants
coming in. Although the federal leases don't give you
production taxes, it's still good for Alaska to have
those barrels going through the pipe.
9:46:21 AM
CO-CHAIR GATTO asked for confirmation that states bordering the
Gulf of Mexico get a percentage of the federal revenue from oil
production because of impacts that activity has on those states.
9:46:50 AM
MR. HAJNY expressed his belief that when a company can show that
projects are not meeting requirements through economic or
technology challenges, the federal government will negotiate to
see what can be done to bring those barrels on stream.
9:47:25 AM
CO-CHAIR GATTO re-stated his question, "Does Louisiana or Texas
benefit from offshore drilling even though it's on federal
waters or do they simply say we're stuck, it's going to come
across our land and enter into our pipelines and finally get to
a refinery? Do they make nothing or something?"
9:47:52 AM
MR. HAJNY said he believes the rules are similar to those that
apply to Alaska, that being that waters within three miles of
the coastline are state waters. The waters between 3 and 6
miles are shared, somewhat. He said BP pays federal royalties
on the Liberty lease, and believes the state will get a portion
of the federal royalties. He was unsure of what law applies
beyond six miles from the coastline.
9:48:38 AM
MS. FITZPATRICK encouraged the committee to also consider the
ancillary benefits of oil production, such as support service
jobs and additional business activity. She pointed out that
although the Liberty project is in federal water, a lot of money
will be spent on that project, which means an economic benefit
to Alaska in terms of jobs for Alaskan contractors and other
benefits.
9:49:35 AM
CO-CHAIR GATTO agreed that more oil in the pipeline makes each
barrel less expensive to move so Alaska and BP have a common
objective. He said the state has no income tax or sales tax.
He pointed out that jobs do not necessarily put revenue in
Alaska's treasury.
9:50:29 AM
MR. HAJNY pointed out that at the Liberty project, the majority
of facilities will be onshore within the Endicott field. Those
facilities would be subject to the same property taxes that
apply to other facilities.
9:50:55 AM
REPRESENTATIVE FAIRCLOUGH asked Ms. Fitzpatrick to speak to the
issue of access to the pipeline by producers other than the
three companies that hold ownership interests.
9:51:40 AM
MS. FITZPATRICK stated that there is capacity in the pipeline
for more oil so any producer has the ability to put its oil in
the pipeline.
9:51:46 AM
REPRESENTATIVE FAIRCLOUGH asked what the transportation cost
would be.
9:51:51 AM
MS. FITZPATRICK said she believes there are agreed processes and
procedures to establish that but she is not familiar with the
details.
9:52:02 AM
REPRESENTATIVE FAIRCLOUGH said she appreciates that
acknowledgement for the record. When she attended a meeting
held by the Governor in Anchorage, a constituent expressed
concern that the big three oil companies are "siloing" oil on
the North Slope by not allowing access to the pipeline for other
wildcat drillers. She asked for assurance that the pipeline
owners allow access at a fair transportation charge to all
producers.
MS. FITZPATRICK said she believes the pipeline is regulated.
9:52:41 AM
MR. HAJNY affirmed that the pipeline is a common carrier
pipeline and the weighted average tariff is published on the
Department of Revenue (DOR) web site.
9:52:47 AM
REPRESENTATIVE FAIRCLOUGH assumed that the hurdle for a wildcat
or small driller is the transportation cost negotiated in that
agreement.
9:53:13 AM
MS. FITZPATRICK said she is unsure about how the rate
regulations are set. She pointed out Alaska is an expensive
place to do business because of its geographic location. She
said many of the costs of Trans-Alaska Pipeline System (TAPS)
are high level fixed costs that are reduced by the number of
units.
9:53:33 AM
CO-CHAIR GATTO inquired whether BP actively encourages other
independent producers to use the TAPS.
9:53:47 AM
MS. FITZPATRICK said BP does not discourage use of or "hog" the
pipeline but she is not sure that it is BP's position to
encourage new companies to invest in Alaska. She asserted:
It's a case of making the investment environment
competitive so as other companies want to come in and
invest in the state. And then if they're finding the
right opportunities, we're certainly not blocking them
of any access to the pipe because it's in our best
interest to have more people in the pipe because that
lowers the cost for everyone.
9:54:36 AM
CO-CHAIR GATTO observed that the owners can assess a surcharge,
or rent feeder lines to the pipeline. He said legislators have
heard the statement that producers make it more expensive for
new companies to operate. When they refer to producers, they
are referring to BP.
9:55:06 AM
MS. FITZPATRICK explained that any facility sharing agreement is
a commercial agreement that is negotiated between the parties.
Those agreements can be complicated, particularly by capacity
constraints. For example, a company might want capacity for
1200 barrels while the available capacity is only 1,000 barrels.
She stressed that more participation is still in BP's best
interest. The agreements are a normal commercial process but
they are complicated.
9:56:06 AM
CO-CHAIR GATTO acknowledged the complications and said he just
wanted a statement from her that BP does not deliberately
oppose, discourage, or interfere with new producers.
9:56:38 AM
REPRESENTATIVE FAIRCLOUGH recalled watching BP ads that state
that the pipeline is two-thirds empty and that time is running
out. They also say Alaska has helped to stimulate continued
production by the existing producers who have been loyal and
done things above and beyond the capacity of other organizations
and that Alaska has benefited from the large oil companies
through employment opportunities and financial contributions to
communities. She noted she does believe there is a barrier
within the FERC and its cost calculations that prevent the entry
of smaller producers on to the pipeline. She said she is aware
of the role that rolled-up rates, the calculation of
transportation costs, and depreciation play in this agreement,
but noted that if BP is interested in putting more oil in the
pipeline it should work with its partners to remove the obstacle
to smaller producers that is part of the FERC ruling on
transportation costs.
9:59:23 AM
MS. FITZPATRICK continued with her presentation, as follows:
The final point I want ... to make on this is around
the interdependence of some of these factors. I
touched on earlier about the infrastructure and the
fact that it was built for 25 or 30 years. That's
also a key thing when we look at the outer years here
and that is, knowing and seeing progress on some of
the larger projects, the technology, focusing on what
the future life might be for the oil on the North
Slope. That's one of the things that we're taking
into consideration when we're starting to think about
what should we be doing around the infrastructure.
What are the investments for the future that aren't
generating barrels themselves but will make it a lot
easier for the barrels to actually flow and to make
them more efficient, not only for ourselves, but for
other players on the North Slope. These projections
here are not just dependent on the existing producers.
They are dependent on new players as well, or on the
existing producers finding new oil through existing
fields and new technology or through new exploration.
Again, sort of listening to the various ...
committees, I am well aware that - and you've
reiterated common goal barrels in the pipeline. I
also think you're all familiar and understand that
more barrels in the pipeline ends up with a better
state revenue position from the royalties as well as
from the PPT.
What this was intending to show is a representative
set of scenarios. That's basically - in order to get
the investment - the decline rate lower requires
significant investment. These numbers were calculated
based on me saying, well, if I want to get to 7.5
billion produced barrels, that's 3 percent. Chances
are from the existing, that's going to be a mixture of
light, a mixture of heavy, and a mixture of new. I
took some of the state's numbers - very simple
arithmetic there - no huge signs behind it, as merely
indicative.
Do I actually think it will cost more? Yes I do and
that's because I think the costs are increasingly -
the activity is increasingly harder and therefore the
costs are going to become increasingly higher.
10:01:51 AM
CO-CHAIR GATTO said all [Alaskans] have been subjected to a
substantial amount of advertising in the form of mail, radio,
television, and newspaper ads that talk about what needs to be
done to increase state revenue. He noted Ms. Fitzpatrick
stated, in regard to investment, "...not only for us, but also
for Alaska." He pointed out that is the first time he has heard
a major oil company representative refer to "us." He stated
when state revenue increases, the oil companies' revenue
increases as well, probably more than the state revenue.
However, the advertising always implies the state is the "bad
guy." He guessed that BP could drill several more wells with
the same amount of money it spends on advertising.
10:04:36 AM
MS. FITZPATRICK said she would do her best to make sure BP
advertising reflects the mutual benefits and repeated that BP is
in a partnership with Alaska that has lasted for 50 years and
continues today.
10:05:13 AM
CO-CHAIR JOHNSON opined that money spent on advertising is not
enough to pay for a well.
MS. FITZPATRICK said her thought was if BP is spending enough on
advertising to pay the costs of drilling a well, she would like
to see the invoices.
10:05:39 AM
CO-CHAIR GATTO asked whether $5 million is enough to drill a
well.
10:05:51 AM
MS. FITZPATRICK answered the costs of drilling vary under
different circumstances. She acknowledged that a previous
testifier used that number last week but that number referred to
"the mother bore," which occurs before the multilaterals or
injector wells are drilled that enable the well to produce.
10:06:20 AM
REPRESENTATIVE SEATON spoke of a previous analysis of Slide 4 by
advisors from Gaffney, Cline and Associates, Inc. regarding the
net present value and dollars per barrel. Their testimony
pointed out that BP is reporting essentially the same cost per
barrel in each scenario. He asked whether the estimates of
production decline, shown on Slide 4, are BP's numbers or the
Department of Revenue's (DOR's) numbers.
10:07:10 AM
MS. FITZPATRICK reminded the committee of her testimony last
week, in which she said all of the estimates are based on DOR
forecasts, so that is what she has said all along. She noted,
for example, the 3 percent decline estimate requires a
substantial amount of heavy oil development, which BP does not
have viable economics to forecast. She is unable at this time
to give estimates on the development cost per barrel because she
does not have one yet. She repeated that the numbers she is
using are indicative and are not representative of what BP's
estimated project costs.
10:08:15 AM
REPRESENTATIVE SEATON asked Ms. Fitzpatrick to provide cost
production estimates at a later date.
10:08:43 AM
MS. FITZPATRICK assured the committee that she will provide
further information about the estimates and continued her
presentation, as follows:
I suspect the point of this slide is well understood
so we will move on from this.
What I've done here is - the slide which had shown the
decline curves in terms of what was from new
investments, etc. - all we've done is to switch that
around into a different format so, as you can see,
this is our estimate based on those numbers of what
would come from Prudhoe and Kuparuk versus other
existing fields and new developments. 70 percent of
the state's forecast production for the next 20 years
will come from Prudhoe and Kuparuk. A good amount of
that will be from the longer term investments and the
ongoing drilling and well work, both for the light oil
as well as the increasingly heavier ends of the oil.
We touched earlier on how we make investments in terms
of around sort of our global portfolio, strategic and
the fact that we take into account technology risk,
economic risk, etc. What I'd like to do is touch on a
little bit of ...
10:10:10 AM
REPRESENTATIVE WILSON interrupted to ask whether the numbers
provided in the remainder of her presentation are from BP or
state forecasts.
10:10:37 AM
MS. FITZPATRICK remarked:
These numbers are how we believe that profile breaks
down and have I been able to verify that? No, but
that we've kind of, on the information that is
available publicly, we can make a reasonable basis of
how we think that would then pull down.
MS. FITZPATRICK explained that the remainder of the presentation
contains numbers from third party agencies and the state. The
following slides about BP contain BP forecasts and individual
contractors have provided their own headcounts.
10:11:10 AM
REPRESENTATIVE WILSON asked if the numbers on Slide 5, regarding
state revenue per billion, refer to the existing 13 wells or $13
billion.
10:11:30 AM
MS. FITZPATRICK explained that the forecast shown on Slide 5
indicates that existing wells will provide $13 billion in state
revenue from 2008 to 2026, based on existing PPT terms and a $60
per barrel Alaska North Slope (ANS) price. She pointed out the
longer term investments are providing a lot of revenue to both
BP and the state. She said BP recognizes that 70 percent of the
next 20 years' production will be coming from the large,
existing fields and is looking at different aspects associated
with that.
MS. FITZPATRICK called the committee's attention to Slide 6,
titled: Developing and Deploying Technology. As previously
discussed, 70 percent of future oil production in the next 20
years will come from existing oil fields; therefore, BP will
enhance production from existing wells by using new technology.
She described the following enhanced recovery procedures: Bright
Water; Multi-Lateral Wells; Cold Heavy Oil Production with Sand
(CHOPS); and Gas Partial Processing. She informed members that a
one percent increase in recovery is equal to about 250 million
barrels of oil. She noted new technology is being tested to
enhance recovery to extract every possible drop and find new
oil. She said BP is now able to drill multilateral wells within
a few feet of where it wants them. Ten years ago, that wasn't
even dreamt about.
MS. FITZPATRICK said BP is also thinking about western region
development, which will require new processing facilities and
significant investment. She noted Alaska has a lot of heavy oil
that is challenged but also has an advantage in that it has
light oil. To make the heavy oil flow down the pipe, BP needs
the light oil to thin it. A variety of technologies can be used
to extract the oil such as Cold Heavy Oil Production with Sand,
thermal, and in-situ combustion.
MS. FITZPATRICK informed the committee that Alaska has heavy oil
in Prudhoe Bay, the Kuparuk River Unit and the Milne Point Unit.
BP has a pilot well ready for testing in Milne Point, and the
right fiscal environment would be conducive to the sanctioning
of this project. In addition to requiring new technologies for
production, heavy oil garners a discounted price on the market
due to its chemical and physical properties. She pointed out
the refineries will have to change their operations to be able
to cope with the heavy oils.
10:17:30 AM
REPRESENTATIVE ROSES surmised that pilot wells test for the
success of the technology and the economics. He asked if the
fiscal climate is determined by the results and cost of
production weighed against the fiscal climate.
10:18:22 AM
MS. FITZPATRICK agreed that the pilot well tests for quality,
flow rate, and the success of the technology. However, one
pilot well will not determine the economics of the field. After
further testing, a stable fiscal environment will be one of the
factors considered when the final decision is made.
10:19:48 AM
REPRESENTATIVE ROSES re-stated his point that the pilot well
will test for oil and the economics of the costs of production.
10:20:12 AM
MS. FITZPATRICK agreed that is a huge contributor.
10:20:17 AM
CO-CHAIR GATTO asked for a comparison of the volume of heavy oil
on the North Slope to that of light oil before it was developed.
10:20:33 AM
MS. FITZPATRICK answered the volume is the same but a couple of
numbers have been used. One is referred to as oil in place,
which is 20 to 30 billion barrels of oil. Of that, about 10
percent is technically recoverable; however the former BP
estimate was zero to three percent, zero recognizing that BP
could drill a lot of pilots and discover the flow rate and
technology have a long way to go. BP is looking at up to 3
billion barrels of recoverable oil. The effect of new
technology on the estimate of what is now recoverable is
unknown. She told members the following:
In terms of there are - sort of some of the technical
risks that we have, when we're making investment
decisions, technical risk is clearly part of it but
then so are the economic risks. This is just
recognizing that Alaska's challenged in many ways, as
well as having many opportunities. We've got light
oil here; we've got heavy oil here. Having the two
together means we are increasing the - hopefully the
likelihood of being able to get that heavy oil to
flow. But we do have to recognize that there's 800
miles of pipe, 2,000 miles of shipping to get to the
West Coast refineries. It is an Arctic environment.
Those things alone mean that it's a higher cost than
average U.S. Alaska is not average and I suspect 99
percent of Alaskans would be horrified if they were
described as average. It's not the way of thinking
here.
So, recognizing that that is the environment, then the
cost structure is different. Now the cost structure
is different because of where Alaska geographically is
and the Arctic temperatures. Costs have also changed
dramatically over the last few years as a result of
global prices and as a result of global prices there's
then been a change in industry activity, which, in
turn, has a driver on costs.
CO-CHAIR GATTO asked if the number on the lower right hand
corner - Alaska $16 average, for the U.S. $10, so that the
differential is $6 per barrel.
MS. FITZPATRICK replied:
Mr. Chairman, there's a variety of data points you
could take. Again, what we've done there is to merely
show the indication of Alaska is a lot higher cost.
The U.S. average is taken from a published document
from J. Herold and Son, and the $16 is actually based
on us pulling together information from states'
information. That doesn't include any capital costs.
It's just the operating, transportation and production
tax.
CO-CHAIR GATTO said he heard the question as recent as yesterday
about whether that number could be $20. He was glad to see the
statement relative to the U.S. as being an absolute $16 and not
$20.
MS. FITZPATRICK said the $10 is absolutely U.S. and [the
additional $6] is a relative position of Alaska being more
expensive. The operating costs included in that $16 consist of
the $7.75, which is from the August PPT report for FY 2008. She
explained that estimate is a blended number from industry's FY
2008 reports to DOR and that her numbers are a subset of the
state's portfolio. She said her actual operating costs are
higher but she is assuming the state has 7 months of BP's
numbers and its forecast for the remainder of 2007, so she is
confident DOR has blended them to come up with this number.
10:24:58 AM
REPRESENTATIVE EDGMON observed that annual reports from the oil
industry specify that 36 percent of the industry's profits in
2006 came from production in Alaska and 27 percent came from the
continental U.S.
10:26:04 AM
MS. FITZPATRICK responded that she prepared a letter on the same
subject for Senator Wielechowski that contained some information
from BP Alaska Incorporated's "20F" filing, and compares its
profit to that of the "BP Group." The BP Group includes retail
activities in Europe and solar and renewable energy. She
stressed when profit comparisons are made, profits from Alaska
must be compared to other BP exploration and production
activities. A regional analysis of BP Alaska's exploration and
production activities included in that same document, which was
prepared for the U.S. Accounting and Reporting Standard No. 69,
and through agreements required by the Securities and Exchange
Commission (SEC). When these are compared, a number of other
regions are more profitable. She said BP Alaska Inc. is a legal
entity that exists to hold investments. It owns investments in
some of BP's Australian downstream activities so it pertains to
areas other than Alaska. However, even with Australia included,
Alaska is not BP's most profitable operation.
10:27:48 AM
REPRESENTATIVE EDGMON asked Ms. Fitzpatrick to compare Alaska to
similar states or sovereign nations in terms of cost structure
and profit structure and its 800 mile pipeline and 2,000 miles
of shipping.
10:28:46 AM
MS. FITZPATRICK advised the committee she would have to first
look at the geology of a region and then at the economic
environment and whether it is more or less costly, and the
fiscal terms. She concluded that Alaska is unique and too
complicated to choose one comparison when making policy
decisions. She said it is important to consider whether policy
changes will increase or decrease the likelihood of achieving
the chosen objective.
10:29:46 AM
CO-CHAIR GATTO agreed that BP, like the Legislature, must
consider its shareholders.
10:29:56 AM
CO-CHAIR JOHNSON asked whether the estimated U.S. average
operating, transportation, and production tax cost of $10 per
barrel of oil includes Alaska.
10:30:18 AM
MS. FITZPATRICK assumed that it did but offered to check and
report back.
10:30:28 AM
CO-CHAIR JOHNSON emphasized that the inclusion of Alaska's costs
of $16 would bring the U.S. average up considerably, since
Alaska produces a large portion of U.S. oil. He suspected the
average would be about $6.00 to $8.00 if Alaska's costs are not
included. He asked Ms. Fitzpatrick to provide the U.S. average
cost if Alaska's oil is excluded.
10:31:25 AM
MS. FITZPATRICK said she would investigate those numbers
further. Continuing to discuss economic data, she said although
Alaska is not average, the economic drivers are similar for
Alaska and the rest of the U.S. She told members the actual
inflation impact has lagged a bit in Alaska. BP's global cost
structure underwent dramatic changes beginning in 2005; that
change did not begin in Alaska until 2006. She told members
that could be due to the fact that Alaska has longer term
contracts because of limited supplies and intense competition
for equipment. She added that when the prices increase on a
sustained basis, costs eventually follow, usually in one year's
time, and a decrease in oil prices will be followed by a
decrease in costs after two years. She opined that, if the $90
per barrel oil price continues, BP will continue to experience
increasingly high production costs. She reminded members that a
net tax structure self-regulates as those numbers increase and
decrease.
10:34:53 AM
MS. FITZPATRICK presented Slide 10, which displays BP's recent
investment activity. Since 2004, BP Exploration Alaska has
increased its number of employees and contractors and is
building infrastructure to sustain the increased activity level
on the North Slope. The cost of investment activity, although
usually considered a negative, is good for the total economic
position of BP and the state as long as the scale and pace of
the activity is ramped up to a sustained level with due
consideration of the limits to production on the horizon. One
of the drivers that can sustain this higher level of activity
and be controlled is tax policy.
10:36:21 AM
REPRESENTATIVE EDGMON referred to Slide 10 and asked whether the
increase in North Slope contractor jobs are jobs held by
Alaskans.
MS. FITZPATRICK replied the 7,000 total contractor jobs are
comprised of Alaskans and non-Alaskans; BP desires to hire all
Alaskans and tries to encourage that.
REPRESENTATIVE EDGMON asked for the percentage of Alaskans
holding the contractor jobs.
MS. FITZPATRICK guessed that 30 percent to 40 percent do not
live in Alaska and offered to check.
10:37:55 AM
CO-CHAIR GATTO acknowledged that Alaska does not have the
population to completely provide the necessary labor for a major
construction project. However, Alaskan schools are now
concentrating more on vocational education in anticipation of
increased investment on the North Slope and the construction of
a gas pipeline.
MS. FITZPATRICK stated that BP is also doing a lot to access
talent at various stages, beginning at the high school level, to
encourage opportunities for future employment for Alaskans. BP
is involved at the university level to encourage offering
courses that develop the needed skills for work in its industry,
especially in the engineering and technical arenas.
10:40:42 AM
MS. FITZPATRICK discussed Slide 11, which shows BP's initial
view of the proposed legislation. She asked members to consider
unintended consequences caused by the new legislation. The first
item pertained to information reporting; she relayed an incident
regarding a request for data from DOR. Alaska's previous tax
policy required one set of data. However, because the tax
process changed 14 months ago, both parties need to find
solutions for the new process of data sharing. Her experience is
that fiscal change takes a bit of time; the industry and the
state are now recognizing the key elements of information that
need to be shared under the new process. She informed the
committee that members have been provided with a summary of the
information BP has disclosed to the state. The two parties now
need to decide what information will be most useful, ranging
from production forecasts to capital costs and a review of DNR's
models. She alluded to confusion in the past about the state's
requirements.
10:44:11 AM
MR. HAJNY told the committee that he was surprised by the
criticism about the lack of information provided by the industry
to the Administration. Each month BP provides cost, expense,
and revenue forecasts for the year. Estimated monthly payments
for the upcoming year are determined in January, based on a
summary of the best data provided. Additionally, BP is required
to provide, along with its unitary tax return form 1065,
partnership returns for each unit. For Prudhoe Bay, under state
income tax return requirements, BP must submit copies of its
partnership joint venture billing returns. Those returns
provide the total annual costs, broken down between capital and
expense. That data provides the state with an idea of trends
developing within a current period.
MS. FITZPATRICK recognized that more work needs to be done with
state officials on this issue, especially with forecasts.
10:46:25 AM
CO-CHAIR GATTO reflected that annual reports provide specific
data that may be collected for different times and purposes,
such as for shareholders or a board meeting. He suggested that
the industry should anticipate what data would be most helpful
to the committee prior to a presentation, and thus avoid a lot
of unanswered questions and assumptions not based on facts.
10:49:45 AM
REPRESENTATIVE GUTTENBERG spoke of information shared by the
industry in partnership reports that is unavailable to state
auditors. Without detailed information from those reports,
auditors don't have a basis for understanding the decisions
made, especially when decisions are based on information from
international holdings. He noted that the details needed by the
auditors are often withheld by the industry as confidential
information.
MS. FITZPATRICK asked whether Representative Guttenberg was
referring to a situation where costs are being charged to Alaska
that are not sourced in Alaska.
REPRESENTATIVE GUTTENBERG restated his concern is that the
state's auditors do not have the ability to look beyond the
state's borders when auditing a taxpayer with international
holdings.
MS. FITZPATRICK stated that the only costs that BP charges to
Alaska operations are directly attributable to BP's operations
in Alaska.
MR. HAJNY expressed his belief that Representative Guttenberg is
referring to joint venture billings and said his point is well
taken. He pointed out that Prudhoe Bay is a partnership field
that is operated by BP and its partners, ConocoPhillips Alaska,
Inc., ExxonMobil Corporation, and ChevronTexaco. He said that
all parties are audited for those billings. He believes the
concern of auditors is unfounded in that scenario because
unacceptable costs would be revealed by other parties to the
agreement.
REPRESENTATIVE GUTTENBERG clarified that he was not making
accusations regarding billings; however, his concern is that
circumstances at an international level may impact decisions
made by the industry in Alaska.
The committee took an at-ease from 10:55:13 AM to 11:19:37 AM.
CO-CHAIR GATTO reconvened the meeting.
11:19:49 AM
REPRESENTATIVE FAIRCLOUGH observed that international
definitions of terms related to the oil industry may be
different in Alaska than in Norway or Venezuela. She referred
to the accounting definitions of the joint agreements and asked
whether the chart of accounts is agreed to, along with the
definitions of contributing costs. She asked, "Are [these] the
same in each of those entities? So, that's question number one,
on the accounting side."
MS. FITZPATRICK answered yes and asked Mr. Hajny to elaborate.
MR. HAJNY further explained that each joint venture partnership
does have a specific chart of accounts that is used for
billings; that was one advantage of using those as a starting
point for audit purposes for each of the interest owners. After
the joint interest billings are categorized and sent back to the
partners, each of the interest owners will use those numbers in
its own chart of accounts for booking and financial purposes.
For the purposes of PPT, each company would have the same type
of category or explanation for expenses. The same would be used
for the joint partnership returns and for federal income tax
purposes. The PPT allows companies to piggyback regarding
whether an item is an expense or a capital cost. That procedure
eliminates the question of whether the item should be an expense
or a capital [cost]. He opined that, in general, a company or
entity is looking to claim any of those expenditures as an
expense on the federal income tax return. In addition, within
Alaska, a taxpayer can receive a credit for a capital expense.
MR. HAJNY assured the committee that the partners have agreed to
a very specific chart and accounting procedure to be used in the
Prudhoe Bay Operating Unit.
11:23:16 AM
REPRESENTATIVE FAIRCLOUGH remarked:
...those charts of accounts feed into your corporate
structure of chart accounts that might be different
then?
MS. FITZPATRICK stated that the joint venture billing is set up
to feed into what the tax requirements are; they differ around
the world. For example, a particular expenditure, according to
a joint operating agreement in Alaska, may be viewed as an
expense or cost item. The same expense in another location may
be viewed as a capital item under a contract. When these
differences must be grouped and reported in financial accounts,
BP will revert to following international accounting standards
and reconciliation will be made under the complete set of rules
and procedures for expense versus capital under both sets of
accounting regimes. Both accounting regimes are very similar
and all reconciliations are made public.
11:24:35 AM
REPRESENTATIVE FAIRCLOUGH asked whether the state has requested
a chart of accounts from BP and, if so, do the auditors have
sufficient information in their possession in order to
appropriately understand the costs reported under PPT.
MR. HAJNY answered:
... yes, we... sat down with them at the end of our
filing for 2006 and explained how our 2006 PPT filing
was developed and walked them through a mapping of how
that tied to our federal income tax partnership
returns, our tax trial balances and how each one of
those specific categories of cost mapped into that.
He confirmed that the state auditors have been provided with
copies of BP's joint operating agreements and accounting
procedures.
REPRESENTATIVE FAIRCLOUGH acknowledged that all parties are in
the first stages of an exchange of information under PPT. She
expressed her understanding that all of the accounts and
information inside of the agreements would be used for the
audits, and said that she would ask the Administration her
question.
MR. HAJNY stated that he and Representative Fairclough may just
be using a little different terminology. The term "chart of
accounts" may not be referred to within the partnership
agreements; another term may be used.
11:26:47 AM
REPRESENTATIVE FAIRCLOUGH responded:
[I'm] just looking for the road map that guides us in
capital expenditures and understanding that in
different countries ... different categories of
expenses could be classified differently and I want to
make sure that the state has the information that
we're seeking.
Mr. Chairman, the final question is in regards to the
replacement of reserve barrels that is shown on
Alaskan assets. Ms. Fitzpatrick and I have discussed
this a little bit so if I'm not clear to my questions
for committee members or to those who might be
listening, the idea is that companies have to disclose
replacement barrels and in that disclosure, that helps
to keep them healthy as far as those who invest in the
organizations may look on as the Security Exchange
[Commission] goes forward with different regulations.
I'm fairly correct to that point?
MS. FITZPATRICK said she would come back to that point after
Representative Fairclough finished her question.
REPRESENTATIVE FAIRCLOUGH continued:
My question to Pedro [Van Meurs] in that Legislative
Budget and Audit hearing was, is there a reason why
Alaskans' resources may be held in the ground because
they can book so many more barrels of recoverable oil
and are those standards and practices globally - the
accounting standards and practices - recognized in the
same way or is there advantage in the U.S. market that
would make our barrels less attractive to move forward
on to market because they can reserve them and hold
them on their balance sheets in a different way as far
as the market goes. I want to know if we have
something somewhere that is advantageous for producers
to hold the reserve barrels on their books instead of
actually producing them. That's the bottom line and
so I want to know how globally the U.S. accounting
practices fit into those globals and if there's an
advantage or disadvantage from BP's perspective.
11:28:33 AM
MS. FITZPATRICK replied in terms of whether reserves and a
replacement ratio are metric and are an indicator of market
interest, the answer is yes. The replacement ratio is based off
proved reserves, which is defined by the SEC. The investment
community is interested in proved reserves but is interested in
other factors as well. The SEC has defined proved reserves very
narrowly and a lot of debate has taken place with the SEC about
whether SEC definitions need to be updated. The SEC regulations
were taken from the Society of Petroleum Engineers' (SPE)
definitions in 1972. Technology has evolved since then so the
SEC is looking into evolving its definitions as well. BP does
not book certain things as proved reserves under the SEC rules
because those rules do not allow that. However BP believes that
some of those reserves are recoverable.
She explained that investors are interested in a few things.
The first is the reserve replacement ratio and how fast those
reserves are being developed and are becoming certain relative
to the amount produced. That is an indicator of the progression
to production. The investment community is interested in how
much of a resource is present. BP believes the heavy oil is
present but needs to figure out how to extract it with
technology and how to extract it economically. She noted:
If I think $100 oil is here forever, maybe I might
think it's economic. Is that a risk I'm willing to
take - entirely different question. So the industry
is interested in - the investment community is
interested in well, what are your resources. There
isn't really a definitive published set of numbers
that would meet resources. There's a lot of stuff
around [indisc.] the Society of Petroleum Engineers.
There's been some stuff around the United Nations
framework, in terms of trying to get some
international standards and, if you are interested,
not in this committee, I'm very happy to arrange for
someone to take you through the United Nations
framework on how it maps to the SPE. There are
various layers of complexity and definition behind
that because ultimately what an investment bank is
interested in is what is the cash flow generation
likely to be and hence, what is also the gross capital
- capital gross - in terms of share price.
Back to Representative Wilson's thought about
assessing your risk profile for your own sort of
retirement. That's what the investor is ultimately
looking for - is what's my capital gross and what's my
return [indisc.] to the dividends. The investment
banks are then working out well what is the flow of
resources around the pinning there and what is the
risk attached to that. They model that quite
extensively so the resource reserve replacement ratio
and the SEC definitions is a subset of what an
investment bank is actually interested in.
11:32:39 AM
REPRESENTATIVE FAIRCLOUGH surmised then that the U.S. markets
take a more conservative approach to the reserve barrels that BP
is holding on U.S. records, because U.S. definitions are lagging
behind world definitions.
MS. FITZPATRICK said that is correct but added that a
significant portion of public oil companies are U.S. companies
or foreign filers; all are required to follow the same SEC
rules. BP's primary reporting is governed by international
accounting standards. The board has not yet set its definitive
rules on reserves disclosure so the SEC rules are used as the
default.
MR. HAJNY added that it's appropriate to view what kind of
reserves Alaska is looking at. He pointed out that DOR's
forecast for production includes more than proven reserves.
Many of the barrels forecasted, particularly in the long term,
are not actually proven reserves.
11:34:15 AM
CO-CHAIR GATTO recalled Dr. Van Meur's testimony about
"bookable" reserves, which no company can declare unless a
reasonable certainty that reserves are likely to be developed
exists. He asked if BP was predicting its "bookable" reserves
based on a 3 percent decline and then shifted to a 6 percent
decline, those "bookable" reserves would have to be removed from
BP's inventory.
MS. FITZPATRICK explained the SEC definitions of proved or
"bookable" reserves include the requirement that BP must
evaluate whether those reserves are economic based on the Dec.
31 price each year. Therefore, a company can have a huge shift
in its "bookable" reserves purely dependent on changes to the
oil price in the world market on December 31. That price impact
causes significant swings for many companies. When BP looks at
its decline curve, it looks at what it can reasonably produce,
its projects, and investment evaluations. That differs from a
snapshot of reserves based on a single day's price.
11:36:13 AM
CO-CHAIR GATTO noted the committees have focused a lot of the
discussion on investment and attaching that to reserves. He
recalled a statement made earlier that if the costs are too high
in Alaska, the [oil companies] would go elsewhere. He pointed
out that would prevent oil companies from being able to declare
those reserves. He stated:
So the feeling has been that if you have $1 to invest
in Alaska and it's going to get you $1.50 in return,
even if there's $1.75 across the street, you'll
actually do both. Isn't that likely? I mean you're
not going to just move your investments somewhere else
based on what kind of a tax deal you get.
MS. FITZPATRICK replied it comes back to a phrase she used
earlier: scale and pace. When BP discusses booked reserves, the
issue is which projects become marginal, in which case BP would
wait for another advance in technology to make that project more
economical. BP's discussion centers on making incremental
projects more valuable. BP does not run its business on
bookable or proved reserves; it is interested in the total
resource base and how to pool that base through to production.
11:38:33 AM
REPRESENTATIVE ROSES surmised that the effect of taxation change
will be long range since the [oil companies] have planned ahead
for 2 to 8 years. An immediate impact could occur if the
economics of a project changes and the "bookable" reserves could
immediately change because that number is calculated annually.
MS. FITZPATRICK said the price at the end of the year can cause
dramatic changes. She continued:
In terms of what impact would a change of fiscal
policy have, I'm not thinking about that actually
purely in the terms of my bookable reserves. It will
have an impact because the point at which - if it's
higher tax costs - the point at which I become not
economic and, by the way, the definition of "not
economic" for the SEC means that you no longer make 1
cent, just to be very clear. It is not around what is
our profit margin. The definition of economic is you
make 1 cent. If I'm down to making those investment
decisions, I'm in a very different place.
So, the choice then around what's happening with the
economic decisions and when would you see an impact?
It will depend on what the impact on that investment
decision is. Are there investments that I have
already started? Yes. Might I change the pace of
them? I might but please don't take that as a threat.
The answer is I don't know yet but would I be
revisiting to look and see what is the right pace? Do
I want to slow it down? Do I want to absolutely keep
exactly with what I'm doing? What about the next
phase of investments? How economic are they looking?
Do I have the next phase of sanctionable projects
coming through?
MR. HAJNY added that as part of a tax organization, he is asked
to look at all of the projects that come through and asked to
provide assurance that the tax assumptions are accurate. While
he can only make assumptions based on the current fiscal regime
in place, he will be asked about the likelihood of that regime
staying in place. Management will want to know whether many tax
policy changes have occurred in the recent past to determine any
additional risk that needs to be placed on a particular project.
11:41:34 AM
CO-CHAIR GATTO said Alaska had no [tax policy] changes for 10
years while oil prices increased substantially. He questioned
whether Mr. Hajny would consider an environment with no tax
changes over a 10 year period to be riskier than an environment
that deliberated and made tax changes over two years.
MR. HAJNY said Co-Chair Gatto's point is well taken. He
explained that prior to two years ago, the assurances he
provided were reviewed [by management] with much less scrutiny
than they are today and he is asked many more questions today
than in the past.
CO-CHAIR GATTO asked if Alberta is keying off of Alaska. He
suspected Mr. Hajny has his hands full when trying to determine
where the tax structure will be stable over the next five years.
11:43:35 AM
REPRESENTATIVE FAIRCLOUGH said one of the reasons she brought up
"bookable" reserves in Alaska is because of current production
rates. She asked why, if oil is at $90 a barrel, production
hasn't been increased to monetize that resource at a higher
value. She questioned why more oil can't be put into a pipeline
that advertisements say is two-thirds empty.
MS. FITZPATRICK said other things need to be taken into
consideration. First, the reservoir must be managed
appropriately so that if production is maximized now, the
reservoir could be damaged and the supply won't be available
later. Second, access to rigs to drill more wells to increase
production might be limited and some rigs may have to be
modified. Whether the costs are economic at $90 per barrel, and
how long that price is likely to last are also factors that are
considered, among others. She noted even if the rigs and
employees are available, the employees may have nowhere to
sleep.
REPRESENTATIVE FAIRCLOUGH noted Ms. Fitzpatrick said costs lag
by about a year.
MS. FITZPATRICK said they do but state whether rigs are
available or will need to be built must be considered.
11:46:47 AM
MR. HAJNY made the following comments about substantive
provisions within the legislation. He said:
[Slide 11] ...The bill changes the statute of
limitations from three years to six years to audit
taxpayers. Our concern is that an additional three
years to audit the taxpayer would potentially subject
us to another three years of interest calculated at
the statutory rate of 11 percent on the findings,
regardless of intent of the taxpayers. BP has
traditionally been very accommodating to the audit
staff and granted extensions to allow time for all of
the audits to be performed and clear up any
misunderstandings on the audit issues as they arise.
One of the concerns is that with the potential for
this increase, these audits could extend on for seven,
eight, nine years, potentially if we granted these
extensions.
The question, I guess, I would ask from a policy
standpoint is might producers be less inclined to
grant these extensions if we continually are subjected
to the 11 percent interest rate because, from our
standpoint of view, that is a significant hindrance
wanting to continue and stretch out audits and include
costs that should not be deductible there.
Moving on to the issue around sharing of confidential
....
11:48:22 AM
REPRESENTATIVE SEATON interjected that a concern about the
statute of limitations was expressed earlier, that being that
overdue reports would be fined on a daily basis so that
extending the timeframe to six years is too long a duration for
that type of fine. He asked if BP would feel more comfortable
if the bill specifies that after a certain time period, perhaps
60 days, the $1,000 fine would kick in so that a company would
have 60 days to comply without being fined.
MR. HAJNY replied the $1,000 daily penalty is related to a
provision to provide information. He felt Representative
Seaton's idea is a good suggestion; however, he still believes
the $1,000 a day penalty is excessive. One of BP's concerns is
that an auditor could come in years down the line and say BP did
not provide information that was requested six or seven years
earlier, therefore a retroactive penalty of $1,000 per day from
that time period could be imposed.
REPRESENTATIVE SEATON surmised that changing that provision so
that imposing a fine for failure to report would come after
notice was given and adequate time for a response was provided.
MR. HAJNY said that would help but he is still concerned that
six years later, if BP didn't provide requested information
th
because it submitted 19 of 20 requested items and felt the 20
item was answered by previously submitted information, the
auditor could determine that information was inadequate. He
said a legitimate oversight could also occur.
11:52:07 AM
CO-CHAIR GATTO noted when collecting taxes, legitimate
oversights and intent are rarely important. The most important
factor is how much is owed. He said when an audit shows that an
item was misreported and more tax is owed when the correct
number is inserted, the penalty is 11 percent annually. He said
if a company is getting an annual return of 35 percent, accruing
a penalty would be economically advantageous. He said 11
percent does not seem outlandish because if the penalty was 2
percent, a company would more likely pick the more advantageous
number. He felt it is the state's desire to encourage accurate
numbers so that penalties do not have to be imposed. He
repeated he does not believe 11 percent is too high and
mentioned the IRS imposes a penalty plus interest.
CO-CHAIR GATTO said regarding the example Mr. Hajny described
with a company responding to 19 of 20 items, the company would
enclose a document describing where the data that responds to
item 20 can be found. Absent a response from the state, the
company would have a case against it if the state wanted to
impose the $1,000 fine six years later. He said that kind of a
fine is not unreasonable when a company decides it is unwilling
to reveal certain data but does not communicate its decision.
He asked Mr. Hajny if he disagrees with charging interest as a
penalty.
MR. HAJNY said through the period of audits, legitimate issues
have come up. They are usually differences in the
interpretation of a law or regulation. They are legitimate in
that they are areas that need further clarification. In the
end, the parties might resolve how to file in the future. If BP
agrees that it owes tax on that particular item, it will pay a
minimum of 11 percent. As BP goes through the audit process
several years down the road, that interest has the potential to
cost more than the original item. His management would
scrutinize that situation thoroughly, which would be significant
incentive to file to the best of his ability and to "be on the
button" about the amount owed.
CO-CHAIR GATTO asked Mr. Hajny if he would like Mr. Iversen to
address the committee.
MR. HAJNY said that would be fine.
11:58:05 AM
JOHN IVERSEN, Director, Tax Division, Department of Revenue,
Juneau, Alaska, provided the following comments:
First off, in regard to the statute of limitations
issue, this is - you know we can come at this in a
couple of different ways. We are dealing with, from
an administrative standpoint, a whole other batch of
costs that we haven't been dealing with in the past.
We've been looking at downstream costs. Historically
now we're looking at upstream costs as well. In
addition, we're also now going to be taking advantage
of looking at joint interest billings and joint
interest audits between the working interest owners in
a unit and the operator. The working interest owners
would do an audit on the operator's billings to them.
Those take time - years. And then, after that there
are going to be some audit issues that are contested
that may remain unresolved for years. Meanwhile the
clock is ticking on our statute of limitations. If it
takes three years for an audit to be completed and
then we've got remaining issues that were contested,
hanging out there, we're bumping up against that six
year deadline even at that potentially - at least the
three year deadline.
CO-CHAIR GATTO asked if the clock stops the moment a challenge
is made or if it continues until the six years is up.
MR. IVERSEN said the clock starts when a return is filed and
resets when an amended return is filed. He gave an example of a
clock starting for 2006 returns when filed in late March or
early April. If that return is amended due to a federal
partnership return, that would be filed in the fall [October].
If the company had to file an amended return [with the state],
the clock would start over. That clock would run until the
taxpayer waived time for logistical reasons. That does happen
often in a cooperative arrangement between the parties because
the state is trying to get the information it needs to finish
the audit. It is to the taxpayer's advantage to submit the
information so that the auditor does not have to guess. If DOR
runs out of time and no waiver is granted, the state has two
choices: to do no assessment or do a jeopardy assessment. The
six year statute of limitations would prevent unnecessary
disagreement and push back on timing. The clock ticks until DOR
makes its assessment so that it has three years from the time
the return is filed to make the assessment, which is the written
statement from DOR of the tax due. He pointed out DOR is up to
speed on its audits. It has not started any comprehensive
audits of 2006 returns under PPT but historically there has not
been a big time lag.
12:03:11 PM
MS. FITZPATRICK said BP doesn't oppose the six-year extension
per se. BP is concerned that an adequate process be designed so
that misunderstandings don't occur. BP is also concerned that
when an audit is finished, if regulations are written during
that time, it does not want to incur a penalty for a good faith
filing for a regulation written subsequently.
12:04:28 PM
CO-CHAIR GATTO asked if a penalty is imposed for failure to
report or for reporting inaccurately or whether only interest is
charged.
12:04:33 PM
MR. IVERSEN said [the bill] contains an additional penalty
portion. There is an important distinction between the
penalties under ACES and the penalties currently in statute.
The penalties under ACES are up to $1,000 per day. The
penalties under current law are based on a percentage of a
deficiency so if the information is not provided but there is no
deficiency or an underpayment or failure to file a return, there
is no penalty. That leaves the information request without an
explicit penalty so if a company does not willingly supply the
requested information, DOR needs to get a subpoena to get it.
Under current law, penalties are based on an underpayment or
failure to file. Those penalties start at 5 percent per 30 day
period or a fraction of that up to 25 percent. A negligence
penalty of an additional 5 percent can also be assessed if the
failure to pay is due to negligence. A fraud penalty of the
greater of $500 or 50 percent of the unpaid amount can be
imposed on top of the others.
12:06:11 PM
CO-CHAIR JOHNSON suggested modifying the bill to say "from the
time of request." The clock would start ticking if that
information is not provided within 30 days of the request.
MR. HAJNY told members that tax filers need a sufficient amount
of time to gather information and 30 or 60 days may not be
enough time. He acknowledged the devil is in the details; the
bill needs sufficient language to ensure the taxpayer is
notified of the exact information requested and the penalty date
and amount.
12:09:06 PM
CO-CHAIR JOHNSON asked if the deadline was 120 days after the
request was made, the fine should be higher and, if it was six
months, even higher so that the hammer falls harder with more
time. The details need to enable DOR to get the information and
provide a hammer to impose that penalty.
MR. HAJNY said ultimately, DOR already has a hammer through
subpoena powers so BP believes DOR has the ability to get the
information it needs now.
12:11:40 PM
CO-CHAIR JOHNSON said as a legislator, he has tried to commit to
not introducing legislation based on snapshots or legislation
that will end up in court. He said if he was to amend the bill
using a subpoena as the hammer, he would be ignoring his
fiduciary responsibilities to the citizens of Alaska. He
thought the Legislature should create clear lines and try to
stay away from subpoenas or legislation that will require a
judge to determine the outcome. He said he is leaning toward a
longer time period and a heavier fine.
MR. HAJNY said he doesn't expect to ever encounter that
provision in the bill but it may be necessary to address issues
that are unforeseeable at this time. BP will provide any
requested information to the best of its ability within certain
boundaries surrounding its legal entities and partnerships.
12:13:32 PM
CO-CHAIR GATTO asked Mr. Iversen if the timely response issue
could be addressed in regulation.
MR. IVERSEN told members he thought the details would have to be
fleshed out in regulations. He clarified that the penalty can
be up to $1,000 per day. If DOR is excessive and unreasonable,
taxpayers can use a three tiered appeal process. If DOR is found
to be unreasonable, the penalties will be abated. He said he
believes that because the subpoena power is a ticket to a court
battle, it is rarely used.
12:15:28 PM
REPRESENTATIVE GUTTENBERG asked how aggressive the industry as a
whole has been in standing up against DOR and how often a case
goes to court.
MR. IVERSEN said that boils down to the respective
responsibilities of both parties. The oil companies'
responsibility is to their shareholders. DOR's responsibility
is to the citizens of Alaska. That relationship often results
in audit disagreements. Generally an audit will turn up
miscalculations or claims that fall in a grey area. Those
disputes are often resolved through the informal conference
process and the additional tax is either paid or DOR backs off.
Many cases go to the Office of Administrative Hearings where
they are decided by an administrative law judge. Some cases go
to superior court but not often. The cost for these cases
increases dramatically with each step so returns diminish the
farther a case proceeds. Once a decision is reached at the
Office of Administrative Hearings, the result becomes public.
Taxpayers are uncomfortable divulging certain information to the
public and there are incentives to settle along the way. Any
settlement must be approved by the Department of Law, as well as
DOR, by statute.
12:18:42 PM
REPRESENTATIVE EDGMON asked if this discussion is directed
toward the added complexities caused by the enactment of the PPT
so is forward looking.
CO-CHAIR GATTO said the discussion started with the extension
from 3 to 6 years and then moved to penalties so the committee
is discussing new provisions in the bill.
REPRESENTATIVE EDGMON asked if the backdrop is the new tax
regime.
12:19:26 PM
MR. IVERSEN said he was framing his comments by contrasting the
ACES $1,000 per day fine with the current penalties. The
litigation and conflicts refer equally to past and anticipated
cases.
12:20:08 PM
CO-CHAIR GATTO asked if ACES will require more auditors because
of increased reporting and auditing.
MR. IVERSEN replied affirmatively.
12:20:36 PM
REPRESENTATIVE GUTTENBERG stated part of the dialog has revolved
around a net and gross tax. A net tax would require more
auditors because of the need to look at operational and capital
costs. He asked Mr. Iversen if he has done an analysis on the
tax division's different needs under a gross versus net tax.
MR. IVERSEN replied the distinction, from an audit perspective
of gross versus net, must be framed in terms of what kind of
gross tax is imposed. Incentives to any gross tax add
incremental layers of complexity.
12:22:22 PM
MR. HAJNY commented he fully understands the need for DOR to
acquire information and is willing to engage in discussions
about how to provide that information. However, it is important
to be very careful about forward looking statements, legal
procedures that must be followed and disclaimers in respect to
them. BP believes certain precautions should be established
statutorily to control and limit access to forward looking
information. BP appreciates that DNR and DOR need to be fully
aware of the legal necessity of appropriate access controls so
that allowing access to confidential and sensitive information
by DNR staff who are directly involved in taking state royalty
in-kind and know to whom it is to be sold and the price would
not be a regular occurrence.
12:23:38 PM
CO-CHAIR JOHNSON said he is very concerned about confidentiality
and understands the state will be a competitor at some point.
He said he was assured by the Administration that its standards
and measures will be adequate. He asked if BP agrees.
MS. FITZPATRICK said she is not sure she can answer that
question because she does not know what the access controls are.
She said if the need for access controls is recognized, she may
have to go forward in good faith. Access controls are not
unusual; BP has them and she has worked for other organizations
that have them as well. She believes access controls are
entirely manageable.
CO-CHAIR JOHNSON commented he believes DOR has said that
confidentiality access controls are already in place and that
everyone in the department has signed a confidentiality
agreement. He asked whether any breaches of confidentiality
have occurred.
MR. HAJNY said BP's view is that its confidential taxpayer
information has been breached on more than one occasion.
Whether intentional or not, that demonstrates BP's concern with
providing confidential taxpayer information and who it is shared
with. Creating certain guidelines to ensure that does not occur
in the future is very important to BP.
12:26:17 PM
CO-CHAIR JOHNSON said it is equally important to him and that it
is incumbent upon the state to protect confidential information
it is given so that companies do not have to decide whether or
not to hand over certain information because of the fear of a
breach of confidentiality.
12:27:12 PM
REPRESENTATIVE SEATON said he shares the same concern but the
problem of confidentiality of tax information can't be cured in
this legislation for one industry; access to all confidential
tax information for all industries needs to be addressed.
12:28:08 PM
CO-CHAIR JOHNSON agreed, but said the Legislature has to start
somewhere.
12:28:20 PM
REPRESENTATIVE ROSES asked what remedies exist for companies
when they feel a breach of confidentiality has occurred.
MR. HAJNY replied the reality is that the processes in place
would make it difficult to acknowledge the specific breach. The
first problem is that BP would be acknowledging specific
information put in the public domain. In addition, BP would
have to pinpoint where the breach occurred and whether it was
intentional. He said the remedies for that problem have not
been adequate in the past to sufficiently protect BP's
confidential taxpayer information.
12:29:44 PM
REPRESENTATIVE ROSES said this legislation has been touted for
its fairness; therefore a company and the state should be
equally penalized for breaches of confidentiality. He said he
will look into placing tougher sanctions on the state for
breaches.
12:30:49 PM
CO-CHAIR GATTO asked when BP has discovered a breach, has it
been able to verify the breach didn't occur within
BP or whether a finger is automatically pointed at the [state
employee] who might have breached the information.
MS. FITZPATRICK said BP would first assume the problem occurred
within the company. A review of internal processes and
controls would take place. She did not want to discuss
specifics, but said BP has had concerns [about state
confidentiality] and believes the issue is important and that
access and confidentiality can be managed.
12:32:21 PM
REPRESENTATIVE GUTTENBERG maintained that both sides have
legitimate concerns. He said whistle blowing on the job is
often encouraged in the industry for the sake of safety. He
felt having a whistle blowing process in place and providing an
avenue of protection should be considered and addressed. He
pointed out that up until this point, the discussion has
centered on leaking trade secrets but inappropriate activities
are occurring in all industries.
12:35:25 PM
REPRESENTATIVE WILSON commented that whether intentional or not,
a breach of confidentiality should never occur so severe
consequences should be created to act as a deterrent.
12:36:13 PM
MR. HAJNY continued his presentation:
[Slide 12] Speaking a little bit about the lease
expenditure aspect of PPT and HB 2001 - from a tax policy
perspective, the determination of whether a tax is
performing we think should be judged on its merits and
facts. Allow the process to work. Perform some audits and
report a complete set of facts and findings. The tax
policy should be based on facts. If, after doing some
audits of the returns, there is a compliance problem, it
should be reported to you for consideration and correction.
The proposed bill asks you to set tax policy without a
full finding of these facts. This appears premature
to me.
We've clearly stated and are committed to cooperating
with the DOR to explain and provide the information to
help them understand our joint venture accounting
processes and these JV processes are an excellent
standard for qualified lease expenditures for PPT
deductions. There's a lot of work that's gone between
the industry and the Legislature and the
Administration to design this system of how taxpayers
will comply with the PPT. But we are very troubled
that the current bill would repeal DOR's explicit
statutory authority under [AS]43.55.165(c) and (d) to
require or authorize the use of operators' joint
venture billings as the starting point for determining
deductible lease expenditures...
CO-CHAIR GATTO asked for the title of the referenced statute.
MR. HANJY answered the section is named Deductible Lease
Expenditures. He continued his testimony, as follows:
...for that unit or field. Why would the
Administration take away the authority to use these
billings unless they intend to disallow them in future
regulations? It's a little puzzling to us there.
CO-CHAIR GATTO asked if Mr. Hanjy is saying that section is in
ACES.
MR. HANJY clarified that AS 43.55.165(c) and (d) have been
removed, which allows DOR to use the joint venture billings as
the starting point.
CO-CHAIR GATTO asked whether that deletion was made in ACES or
by the previous committee.
MR. HANJY told members that section was deleted in SB 2001 and
HB 2001 but it is currently in both versions of the committee
substitutes.
CO-CHAIR GATTO asked Mr. Hanjy if BP wants that section deleted.
MR. HANJY said BP wants those provisions put back in the bill.
He noted the current provisions within PPT are sufficient.
12:39:42 PM
REPRESENTATIVE ROSES asked Mr. Hanjy to discuss advisory
bulletins noticed on the previous page.
MR. HAJNY said he used the categories originally used by the
Administration as the specific provisions within the bill. From
an administrative standpoint, BP is fully supportive of posting
advisory bulletins. He understands the purpose of posting the
bulletins is to potentially prevent future conflicts.
REPRESENTATIVE ROSES asked Mr. Hanjy if he thinks the advisory
bulletins could be used to trigger the beginning of a limitation
or look-back in terms of penalties.
MR. HAJNY said he wouldn't know how DOR could use those
bulletins to calculate interest. It would be a concern, but BP
has been more concerned about being able to obtain affirmative
decisions on specific questions asked about the interpretation
of a current bill. Any information that provides clarity is a
positive step.
12:41:48 PM
CO-CHAIR GATTO asked Mr. Iversen to comment on that topic the
next time he addresses the committee.
MS. FITZPATRICK informed members that other agencies post
bulletins. The SEC posts bulletins when asked how [a rule]
actually applies to let people know. She requested that DOR
post the bulletins in a place that is easy to find.
12:42:45 PM
MR. HAJNY said BP believes it has filed a compliant 2006 PPT
return and followed the laws and regulations when making its
2007 estimated payments. Specific areas need to be addressed
under the regulations; BP encourages the Administration to
complete Phase 2 of those regulations. BP understands the
principles behind PPT and the joint venture billings to define
lease expenditures. He said expenditures such as advertising,
lobbying, tax planning and charitable contributions have not
been included in BP's current filings. The PPT requires
deductible lease expenditures to be direct and ordinary and
necessary costs of oil and gas for exploration, development,
production. The IRS defines the words "ordinary and necessary"
in the same way. He noted the PPT relies upon the federal
definition of "capital" and "expense." BP believes that is an
asset to the PPT.
12:44:00 PM
REPRESENTATIVE ROSES asked Mr. Hanjy to repeat the list of items
that are not deductible.
12:44:12 PM
MR. HAJNY said he cited the following examples: advertising,
lobbying, tax planning and charitable contributions.
12:44:28 PM
MS. FITZPATRICK clarified those items were given as examples and
do not represent the exhaustive list.
12:44:36 PM
REPRESENTATIVE SEATON noted a provision in PPT says if the joint
venture partners reject a bill that would be reason for the
state to reject the deduction as a lease expenditure. He
questioned whether that section will be changed by ACES or the
committee substitute.
12:45:18 PM
MR. HAJNY affirmed that is a concern of BP's because if joint
venture billings are used as a basis for allowable costs, they
should also be the basis in the other directions - which costs
are allowed and which are disallowed. BP has filed with the
understanding that as Phase 2 of the regulations are
implemented, the joint venture billings would be used as a basis
for first looking at what the partners allowed or disallowed.
That would provide a first cut at whether or not to include
those costs. Within that, 18 items are specifically excluded so
that just because a partner paid its share of an excluded item,
that item could not be included in the filing.
12:46:35 PM
REPRESENTATIVE SEATON referred to the recent leak on the North
Slope and the need to replace pipe, and asked if that billing
has gone to the partners in the joint venture and whether the
billing was accepted or rejected by them.
12:47:02 PM
MS. FITZPATRICK replied BP has not yet included any deductions
in its PPT filings.
12:47:15 PM
REPRESENTATIVE WILSON asked what is to prevent the partners from
getting together and planning what to deduct.
12:48:02 PM
MS. FITZPATRICK replied that would not happen for several
reasons: legal requirements, such as the controls required
under the Sarbanes-Oxley Act; BP's code of conduct on how
employees conduct business - avoiding an appropriate tax rule
would not be condoned; and partners are very tough on each other
and none of them want to pay the other.
12:49:17 PM
MR. HAJNY informed members the bill goes to the extreme by
allowing lease expenditures to be determined by regulation.
Taxpayers will not know whether they are filing a compliant
return because regulations can change with the stroke of a pen.
The taxpayer will have no stability under this approach and the
Legislature could only react to changes after regulations had
been promulgated.
12:50:05 PM
MR. HAJNY commented on the costs for unscheduled interruptions:
The exclusion of costs for unscheduled interruptions
of production feature is not a provision that is, in
our opinion, able to be administered. It will create
uncertainty and an area of constant debate and dispute
in the future. It was thoroughly discussed last year
and in the spring, and verified this year by Dr. Van
Meurs and Dan Dickinson that the 30 cents a barrel
exclusion was put in place to simplify and cover the
costs associated with costs that the state did not
want to be deducted due to maintenance costs.
12:50:50 PM
CO-CHAIR GATTO asked if the Legislature should increase that
amount to 50 cents to take care of some of the unscheduled
costs.
12:51:00 PM
MS. FITZPATRICK jested she can only answer that one way - no.
She elaborated the difficulty of working out what an
"unscheduled interruption" is. She said some unscheduled
interruptions are assumed to occur in a large facility because
of the amount of machinery involved. Sometimes the interruption
can be an extension of a planned event. She told members:
...You go in and you're doing some planned work and
you're like well, I could sort this now or I can come
back and do it another time. It might be better to
say actually no, let's extend this and plan for the
future and do something now as a good investment for
the future rather than saying no, I won't do it now,
I'll come back and do it later. That's what we're
meaning by unintended consequences. I think it would
be very, very difficult to administer. As Bernard
said, the conversation last time, I believe, went
round this and it was the 30 cents - I have no idea if
it's the right or the wrong number but that was viewed
as a manageable way to do it.
12:52:57 PM
CO-CHAIR GATTO said the words "unanticipated interruption"
literally jumped off the page at him. He stated:
If I said gee, if I were at the oil company and I had
an unanticipated shutdown...[or] interruption, then I
would say rather than have an unscheduled interruption
tomorrow at 2:00, I think I'll just schedule one today
for tomorrow at 2:00 and now it's a scheduled
interruption and we've done away with the difficulty.
The other term was "unanticipated" to substitute for
"unscheduled." I said I wonder if that's the intent
of the person who put this in the bill really meant.
Either way, I was tending to think like you did. It's
complex and, for instance, Alaska Airlines tickets I
was looking at this morning, it said on-time rate - 40
percent outbound, 50 percent inbound. I said that's
pretty terrible. Are those scheduled? Apparently, at
least they're telling us that's their record. So, is
there a better way? Rather than striking the terms,
is there a better substitute because I think you know
the intent of saying when we lose revenue as a basis
of somebody's unscheduled something that happened
anyway and we think you are smart enough to have known
this would have happened, should we take the loss or
should we say we're going to disallow that as an
expense? That's where we're going on that one.
12:54:43 PM
MR. HAJNY said Dr. Van Meurs came up with the 30 cents per
barrel solution because he recognized that getting language
around that would be very difficult. He believed the 30 cents
would cover the state in those areas for a period of time. He
submitted that over a period of time, there will be many times
when no unanticipated events occur but the 30 cents will still
be excluded from costs.
12:55:32 PM
REPRESENTATIVE SEATON said this issue revolves around the
subject of the [recent] spill and the replacement of the line on
the North Slope, as well as trying to prevent that future
conduct. BP has pleaded to criminal negligence in that
situation. He referred to Section 6 of the bill before members
and said language was added to Section 6 that says, violation of
law or failure to comply with obligations under the lease,
permit or license.
The Legislature wrestled with SB 80 and the definition of
"improper maintenance" and how that could have a huge effect on
the industry. Now the Legislature is wrestling with the term
"unscheduled interruption," which could also have a huge ripple
effect. Obviously the Legislature is dealing with the subject
and the bill is moving forward. Members are trying to figure
out how to work this into the bill so that it has the least
amount of detrimental effect on future operations. He said so
far three suggestions have been made: increase the 30 cent
deduction and clarify Section 6 and Section 19. He asked if BP
has any suggestions on how to cover this issue with the fewest
ripple effects and unintended consequences.
12:58:17 PM
MS. FITZPATRICK said she does not have a suggestion. BP has
said it will follow the tax law when it files its PPT returns.
Whenever BP files a tax return, it consults with its legal
advisors about compliance with the law.
12:58:58 PM
REPRESENTATIVE SEATON asked:
If, on Section 6 - that's on page 26 of L version, we
would have violation of law, criminal negligence, or
failure to follow lease and then that would cover the
events on the North Slope last year that was that
interrupted service and all. If we would do that, do
you see any necessity or benefit for having Section 19
and its uninterrupted consequences and duties to ...
the standard of care and those kinds of things. Do
you see any benefit to having Section 19 in there if
we would include criminal negligence under Section 6?
1:00:00 PM
MR. HAJNY responded if the intent of that language is to prevent
those types of costs, he would see no need for Section 19. In
addition, he would see no need for the 30 cents per barrel
exclusion that also covers the costs the state does not want to
share in.
1:00:36 PM
REPRESENTATIVE GUTTENBERG said from his perspective, this issue
is one of stability. Legislators are trying to determine the
best position and course of action to take. The state's and
industry's planned development on the North Slope is to
increase, or at least maintain, production. He said it is
important that the Legislature and public know the oil companies
are doing the [maintenance] that needs to be done or, if they
have made an economic decision to cut maintenance costs and that
backfires, damages will be paid. He repeated this issue is very
important to the public and they are putting pressure on
legislators to address it.
1:03:50 PM
CO-CHAIR GATTO asked Mr. Hajny to conclude his presentation.
1:04:12 PM
MR. HAJNY told members:
The issue around the topping plant or diesel plant
exclusion on the North Slope - the exclusion of the
costs for building or operating the crude oil topping
plant that provides diesel for field operations is a
peculiar tax policy call in our opinion. It would
disallow costs for building and operating plants that
would provide ultra-low sulfur diesel fuel to the
North Slope operations and potentially villages.
While "incentivizing" operators to import diesel at a
much higher cost of supply while having 50 to 80
trucks on the Haul Road - and that's according to the
Conoco testimony that they provided - every day, the
potential safety and environmental hazards, hazardous
concerns of this policy are troublesome to us.
1:05:06 PM
CO-CHAIR GATTO pointed out that Representative Seaton has looked
into ways to provide economic advantages.
1:05:21 PM
REPRESENTATIVE SEATON said the existing diesel topping plant was
built [on the North Slope] without tax deductions or credits, so
nothing would prevent another ultra-low sulfur diesel plant from
being built. The question is whether the Legislature is going
to allow a tax subsidy for that in opposition to other
refineries in the state. If the state does allow the subsidy
under PPT or ACES, it will not only be giving a capex deduction
and opex, it will also forego any royalty paid on whatever is
used in the plant. He explained if it is in an existing or
other constructed off a leasehold site, the state will receive
the royalty on the oil. The Legislature is looking at this
issue from a subsidy standpoint rather than from the standpoint
of preventing a plant from being built on the North Slope. He
asked if BP has the same perspective on that issue.
1:06:59 PM
MS. FITZPATRICK said BP would consider whether the project is
economic versus other projects. An unintended consequence from
an environmental and safety perspective is the number of trucks
traveling the Haul Road with diesel and the associated risks.
1:07:52 PM
MR. HAJNY told members the last new exclusion in the current
version of the bill applies to DR&R costs. That exclusion
creates a significant amount of issues in the future. He gave
the following illustration. An operator decides to shut down
two gathering facilities in the future to build a more
efficient, centrally located facility but that facility will not
directly replace one of the original structures. Under the
current bill, the cost of dismantling and removing the existing
facilities would not be deductible. He asked members to
consider that policy call.
1:08:52 PM
REPRESENTATIVE GUTTENBERG said he thought BP had been taking
DR&R deductions for a long time. Monies for DR&R have been put
aside for just that purpose. He asked if BP is asking for
additional credits to dismantle a facility.
CO-CHAIR GATTO added the state has collected 5 cents per barrel
for TAPS DR&R. He was unsure whether any money had ever been
collected for the gathering lines.
REPRESENTATIVE GUTTENBERG said the 5 cent per barrel charge is
for a different fund, not the DR&R fund.
1:09:45 PM
MS. FITZPATRICK said when differentiating TAPS from the North
Slope, she was not sure what BP has collected regarding DR&R,
but BP is looking at, when assessing projects, the current and
future infrastructure. In the aforementioned scenario, BP could
choose to maintain two power plants but they are using 30 year
old technology. BP could also dismantle them and build a new
plant using new technology. The new plant would be more
efficient and would benefit BP, as well as other new entrants.
The economics of that decision will be dependent on whether the
DR&R provision remains excluded.
1:10:55 PM
REPRESENTATIVE ROSES asked if under the current PPT bill, BP
would get an exclusion for the DR&R, and capital credits and
deductions for building the new plant.
1:11:12 PM
MR. HAJNY clarified that under the current version of PPT,
certain calculations apply to deductions for any dismantlement,
replacement and removal of items put into service prior to April
1, 2006, depending on how much was invested before and after
that date. He verified BP would get a portion of that and a
deduction and potential credit if putting in the new item is a
capital cost.
1:12:10 PM
REPRESENTATIVE ROSES asked if BP would expect operating costs to
decrease with one plant, rather than two; therefore operating
costs would be lower, deductions would be lower and state
revenue would be higher.
1:12:22 PM
MS. FITZPATRICK said that would be the objective. When
assessing a project, she would look at cost efficiencies. She
said, in regard to the power plant, if the cost is lower, the
deduction would be lower. The lower cost would also benefit
others accessing that power.
1:13:02 PM
REPRESENTATIVE ROSES said he would like more information on that
topping plant, specifically at what level of deduction the
gallons of diesel fuel would be deducted as an expense. If the
state is subsidizing the plant, it should not be giving a full
deduction for the full dollar value of each gallon because the
price would be lower if no royalties or taxes are paid.
1:14:02 PM
MS. FITZPATRICK agreed to provide the specifics. She said her
initial understanding is that it wouldn't be both.
1:14:16 PM
MR. HAJNY continued:
Many of you remember there was a considerable amount
of debate surrounding the transitional investment
expenditures, or TIE credits, during the previous
debate on PPT. After much consideration, the
Legislature modified the tax credits by requiring a
TIE and tying the credit to our future spend. A
producer must spend $2 in the future to receive a
credit of $1 spent in the prior years. Keep in mind
that there's a fixed amount of credits available for
each company under the current TIE credits. It's just
a matter of how fast a company is eligible to take
them and whether they invest the money over the first
seven years of the PPT to be able to take the eligible
credit. Remember that these particular credits would
expire in 2013. The Administration has stated that
the amount of TIE credits that were taken last year in
the filings was approximately $114 million by the
industry. They were surprised by that level of
credit. The question that I had is isn't this exactly
what the credits were intended to do?
1:15:25 PM
In the same line around credits, the current version
of HB 2001 and SB 2001 changes the 20 percent capital
credit and spreads it over a two-year period, causing
additional administrative burdens and complexity for
both the taxpayer and the Department of Revenue that
is not needed. As Mr. Van Meurs noted, it reduces the
incentive targeted by the credit but still costs the
state the same amount of money in the end, with the
exception of what we would consider a tax increase in
the very first year because there's no period of time
to capture that credit in the first year of the
implementation. So, in our opinion, it just reduces
the overall economic impact to any project that will
be considered in the future.
1:16:30 PM
MS. FITZPATRICK summarized by telling members 70 percent of the
next 20 years' production is currently forecast from Prudhoe and
Kuparuk. Tax increases will create an economic change, as well
as the current committee substitute, which changes gross
progressivity. That will not provide flexibility for future
changes, whereas a net tax would be self adjusting. She
cautioned:
By that I mean we're in an unprecedented world at the
moment of $90. If that stays, and costs then catch
up, there may well be opportunities that today I
wouldn't be thinking were robust price tags to look
at, which could well be in the higher ends there. But
if costs are caught up with that and I'm in a gross
progressivity, which is kicking in a lower rate, that
might, in fact, have the counterintuitive impact of
impacting investment decisions at a time when you
would think I should be actually encouraged to do
more. So that is something that I would encourage you
to think about in terms of is going to a gross
progressivity in these environments actually going to
give you the flexibility to encourage the investment
at the higher ends if that's in fact where we end up
re-equilibrating at.
Key messages - I'm not going to read the slide to you.
You're all perfectly able to read the slide. It's
about what's the policy you want to put in place.
It's about investment. Ladies and gentlemen of the
committee, you all understand that and I appreciate
your balance is trying to decide how to get the right
answer for Alaska's economic future. I'd like to
thank you for your time and your questions. I have a
list of about 4 or 5 things which I've taken, which
were specific requests that we will do our best to get
back to you as soon as possible and, hopefully if you
have follow-ups, we're very happy to take them.
1:18:32 PM
CO-CHAIR GATTO said it is interesting to see the word
"uncertainty" bolded. He said certainty and predictability are
terms given to the Legislature by the previous Administration.
He ascertained the state wants the same things.
1:19:00 PM
MS. FITZPATRICK said all one can do is try to manage
uncertainty; eliminating uncertainty is unlikely. When making
investment decisions, she tries to balance many uncertainties.
CO-CHAIR GATTO thanked Ms. Fitzpatrick and Mr. Hajny for
discussing BP's concerns with the committee. He pointed out the
word "partnership" is very valuable to legislators; they want to
have a partnership with BP, not a confrontational relationship.
Both parties have done a fair amount of work to create a
partnership and trading information has helped that partnership.
1:20:27 PM
CO-CHAIR GATTO announced that the committee would recess until
2:00 p.m.
2:17:37 PM
CO-CHAIR GATTO reconvened the House Resources Standing Committee
meeting and asked Mr. Mitchell and Mr. Taylor of ConocoPhillips
to present to the committee.
2:17:53 PM
KEVIN MITCHELL, Vice President of Finance and Administration for
ConocoPhillips Alaska, Inc., began his presentation, as follows:
... With me today is Jim Taylor, who is Vice President
of Commercial assets for ConocoPhillips here in
Alaska. What we'd like to do today is take you
through a little bit of ConocoPhillips' overview.
We'll touch on that a little bit to set the stage and
give some comments on our perspectives on PPT and how
we see PPT performing.
We'll then go on to talk a little bit about what we
see the future resource potential being and being on
the North Slope of Alaska for our industry and
transition that into how we see the tax structure as
being integral to how the North Slope development will
play out in the coming years. And then we'll get
specific on certain areas of the bill that we want to
comment on. So with that, what I'd like to do to
start with is just give you a little bit of overview
of ConocoPhillips in Alaska.
2:19:08 PM
Pretty much by whatever way you look at ConocoPhillips
in this state, we come out as the number one - in the
number one position whether it's on a production means
- we're responsible for some 35 to 40 percent of the
state's oil production. We're not too far behind that
percentage on a gas basis with our Cook Inlet
operations. We're the largest lease holder in the
state with an interest in some 2.6 million undeveloped
acres outside of the existing developed acreage.
We've been actively involved in exploration over the
years. As you look at all of the key components of
the industry here in Alaska, whether that's the
original Legacy fields of Prudhoe Bay and Kuparuk, the
development in the western North Slope, that's Alpine
and the satellites there, the Cook Inlet developments
and the exploration, we've been actively involved in
all of those sectors of the business here in Alaska.
Alaska has been very important to us. We've been here
for some 50 years or so. It will continue to be very
important to us and we look forward to a long and
continuing relationship with the state as we look
ahead.
2:20:44 PM
MR. MITCHELL continued:
So, as we move on - just to give some summary
comments. First point here is we really believe there
needs to be alignment between the industry and the
state. What is good for the industry is good for the
state. When the industry is having hard times, the
state is in hard times as well. There's been a lot of
talk over the last several days about the economics of
projects and when a project is economic or what makes
it not economic. The reality is we want economic
projects because that delivers a return to us and to
our shareholders, but the same applies to the state
because an economic project by definition means it's a
project that's going to be generating tax and royalty
revenues that go back to the state. So, in that
regard, there really is a common alignment as we look
at that.
We do think that with the PPT legislation just being
enacted last year, it's very soon to do any kind of
fundamental change to that legislation. It's
unsettling from an investor perspective to have that
degree of tax changes on such a frequent basis and
we'll talk a little bit about that.
Generally speaking, tax changes will have an impact on
the investment climate and we'll spend some time, as I
said, talking about the future resource potential and
how the fiscal structure can have an impact there.
2:23:08 PM
MR. MITCHELL continued:
We can't get away from the fact that when the tax take
increases, the investment climate looks less
attractive and then the frequency of tax changes also
adds a kind of stability question mark around that.
And then the last comment is that there are several -
I'll call them administrative provisions in this bill
and we just want to make sure that they all get the
appropriate thought and consideration that they
deserve before any of that becomes law, not to say
that we don't necessarily agree with the intent of
what's behind a lot of those but want to make sure to
get the right consideration as we go through this
process.
Just to go through a little bit of background, what
this - the chart on this slide [Slide 4] represents
the production tax revenue forecast. The first bar,
the short bar that goes up to almost the $500 million
mark represents the Department of Revenue's spring
forecast back in the spring of 2006 forecast for FY
2007. That forecast was done under the ELF regime and
that showed that $500 million projection.
The next two bars represent the forecasts for that
same fiscal year - the first one - what was contained
in the PPT fiscal note. The second slightly taller
bar, slightly above the $2 billion mark is what was in
the Department of Revenue spring 2007 forecast, again
for FY 2007. There's been a lot of discussion around
how the actual results came in compared to the
expected results. There are three major components,
as you know, with a PPT type calculation. There's the
price piece, there's the volume piece, and there's the
cost piece. Every one of those will have an impact on
the actual end result. The reality is every one of
those came in the actual - or as close to the actual
as we can determine - came in quite different to what
the original fiscal note projected. However, when you
roll it all up together, it comes in really not too
far apart and to look at - if I knew the price was at
this level, then I should have gotten a different
number. It kind of ignores some of the reality of
it's not a static environment where one item will move
and the other components will stay static.
I've been involved in the finance business of the
industry for many years and I've spent a lot of my
career explaining to senior management why actual
results didn't come in line with forecasts or budgets
or projections. All the time the explanations are a
combination of price, volumes and costs. That's the
nature of the business that we're in.
2:25:33 PM
MR. MITCHELL continued:
So I have sympathy for the situation the
Administration's been in. This was a significant
change, this move to a net structure and it's not
easy. But I do believe that as we progress over time,
that will somewhat rectify itself as they have more
experience with that system. We have more experience
of the Administration trying to work with that system
and helping - providing them with the kind of
information that they need as they move forward. So,
I think just to round that out, it just to me
emphasizes that is it really the right time - is this
- the reasons for going back in and making a
significant change to the tax structure?
2:26:20 PM
MR. MITCHELL said Mr. Taylor would talk more about future
resource development on the North Slope and then revisit how the
tax structure will impact that development.
CO-CHAIR GATTO welcomed Representative Johansen to the
committee.
2:26:40 PM
JIM TAYLOR, Vice President of Commercial Assets for
ConocoPhillips, said he would try to describe what
ConocoPhillips sees as the future potential of North Slope oil
and gas resources, ConocoPhillips' participation in those
resources and describe those in enough detail so that Mr.
Mitchell can follow-up with the taxation aspect.
2:27:28 PM
MR. TAYLOR told committee members:
The way I'd like to start is to address this same
curve and I think our partners before testified to
this curve. It looked a little bit different but what
this is the Department of Revenue's future forecast
and I've just captured a time frame by which I will
state a few statistics to try to emphasize our view of
what this represents.
The first thing I'd like to say is that ConocoPhillips
is proud to report to the state that we participate in
all levels of these projects - all the way from
wildcat exploration all the way through final Legacy
field production and all the developments that ensue
in between.
2:28:10 PM
CO-CHAIR GATTO asked if, by saying ConocoPhillips participates,
he is saying it supplies all of the documents the state has
requested and more.
2:28:20 PM
MR. TAYLOR clarified the context of his statement is that
ConocoPhillips invests and participates in a project from
wildcat exploration through to production.
2:28:39 PM
MR. TAYLOR continued:
So what is set up in this slide are four layers of
future production as forecasted by the Department of
Revenue, the top layer being new fields that are
brought on line; the yellow layer being those other
areas outside of the anchor fields or the Legacy
fields as they've been referred to. It represents
production from Alpine, Fjord, Northstar, Nanook and
others.
The large red wedge is a wedge that I'll further
describe later as being those oil and gas resources
associated with Kuparuk and the greater Prudhoe Bay
area and the blue being a representation of an
estimation of what Kuparuk and Prudhoe Bay would look
like without the investment that would be required to
fight the natural production decline that occurs in
oil and gas assets.
What we've imposed on there is a 15 percent decline
and I think what you have on the top of the red is
about a 2 percent decline. I'm not here to advocate
the precise nature of each of those, but what I'd like
to do is describe what's contained in those and what
we see as an investor is necessary in order to bring
those to light on behalf of our investors as well as
the state.
What I'll point out is the way I look at this is over
the next eight years, in 2016, to visualize what needs
to happen in order to sustain this level of
production. I've kind of broken down what percentage
of each of these layers is in 2016. The top layer
represents about 15 percent of the total production
that is forecasted by the DOR in this particular
forecast coming from new fields. 15 percent will then
also come from those fields outside of Kuparuk and
Prudhoe Bay, such as Alpine, Northstar and others, but
the single largest pieces are those that come from
Kuparuk and the greater Prudhoe Bay area. That
represents about 42 percent of the production and it
will require, I think as testified earlier, require
significant investment to bring that to light. And,
of course, without the investment you can see that the
production in those two large fields will decline to
represent as little as 30 percent of the total
production potential during that period.
What is contained inside the red wedge? The red wedge
consists of projects such as infield drilling, wells
that are added - you heard described earlier this
morning - that bring on new production. As we
produce fields, we learn about the complexity that the
reservoir has in it.
2:30:59 PM
MR. TAYLOR continued:
We modify where we drill wells. We move bottom hole
locations to help exploit and bring to light the
production that we learn is represented in different
ways. So there is a lot of side track and infield
drilling potential that goes into a field throughout
its life.
There are other projects that are referred to as
improved recoveries. Prudhoe Bay, as an example, is
one of the most complex reservoirs in North America,
if not the world. It has a combination of recovery
mechanisms that all interact with each other. It's a
very large field that has primary depletion, natural
depletion that goes on. There's water injection.
There's miscible gas injection and then there's gas
cap depletion that goes on. Let me assure you, it's
one of the most complex that I've encountered in my 28
year career.
So with that comes a lot of opportunities to optimize
along the way the things that we learn about the
field, such as how do we handle the ever increasing
amounts of water that come with production. That adds
cost. It adds complexity. It adds changes in how you
maintain the assets because the composition of the
fluids is changing. You start to have higher gas
production rates, which require more reinjection,
additional costs, and greater complexity as well. So,
the improved recovery projects are contained inside of
that and will require continued reinvestment in order
to bring those reserves to light.
And then one that I'll spend a lot more time on in the
coming slides are those that I think you've heard
described briefly before and those are the reserve
potentials contained in the viscous oil reservoirs, as
well as the heavy oil reservoirs. What I'll show you
is that that is a significant reserve potential that I
think you heard testified earlier as being something
that we want to work very hard at learning how to
unlock and bring to light.
2:32:46 PM
So, the key message from this slide is that the
investments of the past that have been focused
primarily on the conventional oil and gas that was
contained in those large fields is starting to
transition, is starting to transform. The North Slope
is moving from just a conventional oil and gas basin
to one that is now going to have an ever increasing
amount of viscous and heavy oil and someday when a gas
pipeline comes to light, we'll also be transforming
from an oil producing region to a gas producing region
in that regard.
So there is a transformation that's occurring and it's
important that we work together to preserve the
investment climate so that we can optimize the
realization of the potential of the North Slope.
2:33:35 PM
MR. TAYLOR continued:
I'll spend just a little bit of time on this slide
[Slide 6]. It is not intended to confuse but this is
a pictorial of the North Slope. It shows in these
areas the outline of the greater Kuparuk unit and the
greater Prudhoe Bay area and then the various colors
represent leasehold acreage by [us], as well as
others. So, what it tries to represent is that there
has been a fairly substantial amount of exploration
occurring in the North Slope over the past. We've
participated in over 60 or those exploration wells
with varying degrees of cost and complexity. Those
that you drill close to your existing producing fields
can cost as little as $8 million. Those when you
start to move away from those existing fields where
you have to start building ice roads and you get off
the pre-existing pads can grow to $12 million or more.
And those in those very remote locations where miles
of ice roads and a tremendous amount of logistical
planning has to go into it, the cost of those wells
can exceed $36 million.
So ConocoPhillips has participated in many of those
prospects throughout the years and have brought some
of those satellite fields to light.
2:34:44 PM
MR. TAYLOR continued:
Another point that I'd like to make on this slide is
basically a statement of the evolution of a lease.
I've heard the question asked: What is being done to
encourage other investors? Are we encouraging the
independents to come to Alaska and work? I would
answer that question as yes we are and I would
describe it this way as that when the company comes in
and participates in a lease round, they see a
prospect, they see potential. As they evaluate that,
they drill wells; they learn things that may change
their view of that lease. Well when, say, someone
like ConocoPhillips says well I've done all that I
wanted to do to try to understand what I thought was
there, there may be others that see other things.
There may be others and a secondary market that says
well I'm willing to take some risks. I see things
differently. So, in that regard, those leases are
made available to other companies. We farm leases out
to the independents. We have partnered with
independents. Anadarko is a partner of ours in the
[National Petroleum Reserve-Alaska] NPR-A and also in
the Alpine field.
So we not only partner with smaller companies ... and
large companies, but we also create a market by which
they can enter the market, whether it's by lease sales
or by amendments to existing leases. So there is a
value chain that I would advocate that we do
participate in that does encourage other investors.
We share rigs. We share in the cost of construction of
ice roads. So there's a lot of cooperation that goes
on that I think enables that and hopefully encourages
others.
2:36:03 PM
Another point that I'd like to make here as I describe
the progressive increase in costs as you move away
from existing facilities, it would go without saying
that Prudhoe Bay being the single largest producing
field in North America, and the largest oil field
found in North America, would also probably represent
the largest field that was going to be discovered on
the North Slope.
What happens in hydrocarbon basins you go through a
creaming curve where typically the larger fields are
found and that what happens over time, there are
smaller fields. So those are conducive to other types
of investors but what I want to show you is that it's
also conducive to the opportunities that lay inside of
the large fields. And hopefully I'll describe that
we're in pursuit of those as well.
2:36:49 PM
MR. TAYLOR continued:
Just a couple of quick points here is that this is
another slide [Slide 7] that represents the Alpine
field and some of the early exploration that has gone
on in that area. This is a remote area. This is one
of those areas that is difficult for those to enter
that haven't been there before and, as I described to
you, I think we're doing a lot of cooperative measures
that makes it possible for others to participate as
well.
But, I think there [are] a couple of points to make
here. Because of the remote nature and the high
regard we have for the sensitivity of the environment
and the footprint that we are impacting, these two
slides show that the exploration in these areas does
leave a minimal footprint and that the amount of time,
cost and effort that goes into building ice roads,
placing in this case a 3 million pound drilling rig
with 160 foot derrick on 12 inches of ice is not a
cheap investment. It's something that has to be well
thought through, done very carefully. And then, when
we're done, hopefully there will be a small production
pad in this area but in this case you'll see that this
exploration well was left inside of a house for future
assessment. There may other drilling or they may come
back and plug and abandon that well and hopefully you
will not eventually notice that that well ever
existed.
So there is a high degree of scrutiny applied to this
environmentally sensitive area but I think the
industry is doing a good job of trying to manage that
along with the interests of the state.
The other point that I'd make in a picture that could
follow up to this is, well what does the development
look like in this area and how does that impose the
cost of what remains on the North Slope. Typically
you'll move from a well pad of this size to a
production pad that is trying to be managed in terms
of its size.
2:38:21 PM
MR. TAYLOR continued:
So the design and the threshold of costs that these
smaller fields can endure in order to create an
economic project are challenged in their own right
because you're trying to compress everything into a
smaller area so you can address a lower reserve size
potential to create an economic venture.
2:39:02 PM
I'll jump ahead a slide here [Slide 9] because I want
to briefly describe some of the large remaining
potential that we see on the North Slope and I think
BP described this briefly in their last testimony and
in great detail in previous testimonies.
The way I'll characterize is - I guess first of all
describe the degree of difficulty and complexity and
we've done that by showing two different densities and
viscosities of crude oil that exist in the various
formations up there. On the left you see that there's
an easier form of flow, and I would describe the 19
API crude as more like maple syrup that goes on our
pancakes. When it's warm it can flow fairly well but
obviously not near as well as the conventional oil and
gas whereas the 10 degree API crude on the right flows
like molasses. So, if we put these types of crude
inside of rocks and bury them 3 to 4,000 feet at depth
and put them at 45 to 50 degrees temperature, they're
going to be challenged at getting them out. So these
are some of the challenges that we're trying to
unearth and crack in bringing this large, large
resource to light.
2:40:08 PM
The other take away from this is the graph on the left
tries to show that many of the geoscientists and
engineers estimate that the resource size, the
original oil in place, is as large as the conventional
oil and gas that was discovered 30 plus years ago.
2:40:23 PM
CO-CHAIR GATTO said he always thought 40 to 90 sounded warm. He
asked whether permafrost exists below and above it because he
had heard the heavy oil was in the permafrost.
2:40:41 PM
MR. TAYLOR said it is his understanding the zones he described
exist below the permafrost.
CO-CHAIR GATTO noted that people have suggested using an open
pit mine concept as is done in Alberta, but the oil is too deep
for that.
MR. TAYLOR said that is his understanding too.
2:41:10 PM
MR. TAYLOR continued:
Alberta obviously has the oil sands that crop out of
the surface and then they vary at depth as you travel
south. They do encounter deposits like this so the
technologies that they are employing are those that we
would be looking to try to test and create commercial
projects in Alaska as well. So I can assure you there
are some very exciting things going on, not only in
Canada, but in some of the South American heavy oil
basins, as well as Alaska. So there are some ground
breaking technologies that are being developed and
employed. I'll show you a couple of them that we're
pretty proud of participating in Alaska.
2:41:42 PM
CO-CHAIR GATTO said that is absolutely crucial to this state and
any successes will benefit both parties. He asked if Alaska's
resource is the most difficult [to develop].
2:42:09 PM
MR. TAYLOR said that is a good question. ConocoPhillips deals
with challenges in many basins. It finds similarities and
differences. Typically the heavy oil deposits exist at
shallower depths. ConocoPhillips, in basins with known
deposits, has drilled through them to look for other deposits at
greater depths. Those deposits were not easy to exploit and
went into inventory because ConocoPhillips didn't know how to
develop them at the time. However, as prices rise and
technologies advance, they become more interesting and worth
pursuing. They challenge economic models. ConocoPhillips is
looking for ways to reduce costs and increase recovery so that
it can pursue those resources.
2:43:17 PM
MR. TAYLOR continued:
Large target, challenged asset results in high costs.
So what I'm going to talk about briefly here is where
they exist and the relationship they have with the
conventional oil that exists on the North Slope. What
I've done here is show, once again, the outline of the
greater Prudhoe Bay area and the Kuparuk River unit
along with the Alpine area.
As you'll see, the green represents the light oil
production in the larger areas. The brown represents
the viscous oil, which we see today as being on the
cusp of commerciality and I'll describe one of those
projects here in a minute. And then the darker heavy
oil is that that is really challenged by cost and
future potential.
The point that I would like to make here is that the
co-location of the potentials, the reservoirs, lay on
top of each other.
2:44:25 PM
So the conventional means of producing the light oil
has typically been through the vertical well.
CO-CHAIR GATTO asked if the reservoirs are in contact or
separated.
MR. TAYLOR replied they are usually separated by a few thousand
feet. A typical conventional oil well will be anywhere from
8,000 to 10,000 feet, depending on the deviation or inclination
of the well. The heavy oil deposits exist between 3,000 and
4,500 feet. They probably had the same source basin of
hydrocarbons but became trapped.
2:45:20 PM
CO-CHAIR GATTO asked whether they have different BTU values.
2:45:26 PM
MR. TAYLOR said the quality differs. Typically, the heavier
viscous oil has a discounted price compared to that of light
conventional crude. Most refineries have been built with a
certain product in mind. As those product slates change, the
refineries must change. He noted many of the refinery
expansions associated with the Alberta oil sands have needed
increased coking capacity. Those investments must be recovered,
which typically comes with a discounted price on the feed stock.
2:46:12 PM
MR. TAYLOR continued his presentation:
Back to the points that I was trying to make here that
the resource potential is very large. The reservoirs
overlay each other. They will utilize some of the
existing well pads. The wells will sit next to each
other because they are drilling a similar area but
they are stopping in different places so they will co-
exist next to each other. So there is some leveraging
that's trying to go on between the heavier oil and the
conventional oil and they're going to try to use the
same existing facilities. But because they are
different products, they do require incremental
investments, not only in the well technology but also
the process technology.
So the underscoring point here - high target resulting
in higher cost and lower recoveries with a longer
production profile, so that challenges the economics.
All of those attributes go into what we use to
calculate an economic project.
2:47:08 PM
MR. TAYLOR continued:
What I'd like to go over here is just a description of
some of the technology that's being employed and
distinguish this and the cost and complexity from the
conventional oil. The West Sak example that I've used
here is a trilateral, horizontal well. As you can
see, it's been completed and utilized some new
technologies to where it's accessing three different
sandstones from the same well bore. That requires a
lot of directional drilling. As you can see, to put
this in perspective, this horizontal section can reach
up to a mile and a half away from the well bore
itself. So it's reaching a long ways. It's utilizing
new technologies and it's overcoming production
problems that we previously had not figured out to do
very well but this technology is advancing.
Once again, a well like this, as compared to a
conventional well, can run up to 12 or more million
dollars so there are higher costs.
The table - I won't go in any great depth but the
point that I'd like to make here is there are other
technologies outside of just drilling that have
advanced in recent years that's starting to bring this
to life. But they do come at a price. They do come
at high complexity. So, the largest potential that
will exist in those deposits I showed you will be
challenged by some of the costs that are occurring.
So anything that could happen to the tax regime or the
fiscal take or anything that will impact the cost, the
price or those things that would detract from the
economics, push these things back and forth on and off
the bubble of their economic viability. And so that's
the point that I was trying to raise here.
2:48:45 PM
CO-CHAIR GATTO noted Mr. Taylor's title is the Vice President of
Commercial Assets and asked if commercial assets mean only
commercially valuable assets or all assets.
2:49:02 PM
MR. TAYLOR said his responsibilities include ConocoPhillips'
interests in the Prudhoe Bay area. He is also a representative
of the owners' committee of TAPS and manages ConocoPhillips' gas
operations in northern Cook Inlet. He has a counterpart who is
responsible for ConocoPhillips' operated assets, which are
Kuparuk and Alpine.
2:49:44 PM
REPRESENTATIVE ROSES said each producer has talked about the
increase in costs. He referred to the mud system on Mr.
Taylor's chart and said that system was water based in 1998 but
is now oil based, which increases the cost. Also, the chart
refers to water flood as a recovery mechanism and viscosity
reduction. He asked if those are the technologies that will
rapidly increase the costs.
2:50:22 PM
MR. TAYLOR said that is absolutely correct; this table shows
that money is being invested to advance technology and that
comes at a cost.
2:50:42 PM
REPRESENTATIVE ROSES said the fact that the mud system is now
oil based means that oil cannot be sold.
2:50:49 PM
MR. TAYLOR said oil based mud systems can range from crude
systems to mineral based oils but they are not necessarily
sourced at the field level. They are brought by service and
other partner companies. They are usually mineral based oil
systems that attempt to preserve the productivity of the wells.
The sands and wells sometimes react unfavorably to certain
fluids. The oil based mud system increases penetration and
helps deliverability but it is more costly.
2:51:38 PM
MR. TAYLOR continued his presentation:
Zooming through the points here - what we've done here
is taken - displayed an aerial photograph of the
Kuparuk CPF 1 production facility. Some of the points
that I'd like to make here and I'll clear this site
fairly quickly is that - once again, the large
production target associated with viscous and heavy
oils is large but it does need to coexist because it
does lay in the same areas as where our conventional
oil does. So what we're working hard to do is make
sure we are leveraging the investments we've already
made but yet we have to enhance those facilities in
order to accommodate this new development that's going
on.
The other point that I'd like to make is because they
are so interrelated, and you can tell by just looking
at the complexity of these ingoing and out coming
lines that represent production flow lines, injection
flow lines, fuel gas lines and gas lift lines, that
there's a high degree of complexity if we were to
consider trying to separate these two. It would be -
I guess I would call it a nightmare. It would be very
hard and actually would add a lot of investment costs
that we had to try to figure out how we could exploit
the heavy oil and separate it from the light oil.
The second point is a technical point - it is that
they do need each other. The heavy oil will have flow
assurance problems as it enters pipelines. The
temperature drops. It needs a way to mix itself with
another component and the conventional oil serves a
very good purpose in creating flow assurance in the
existing pipeline technology.
2:53:15 PM
CO-CHAIR GATTO asked if heavy oil has a different paraffin
content than light oil.
MR. TAYLOR said typically they do but not always.
CO-CHAIR GATTO asked if it is more or less.
MR. TAYLOR answered:
More. Their pour point is at a much lower temperature
- or at a much higher temperature they start to
thicken up and have a hard time with their flow
characteristics so, in the earlier days, say 10-15
years ago in Alberta, they were using a lot of natural
gas liquids to mix with the heavy oils in a lot of the
pipelines to keep them thin enough so that they would
flow.
2:53:44 PM
MR. TAYLOR continued his presentation:
Now that the NGLs are a fairly scarce commodity, they
are moving to synthetic oils that are actually
manufactured for this sole purpose mixed with the oil
to keep them flowing. In this case, we think that
there's a tremendous synergy that the health and
wealth of conventional oil is something that can be
mixed with the heavy oil and help with that flow
assurance. It's estimated - it could be a requirement
of 1 to 1 - one barrel of heavy viscous to one barrel
of conventional that would continue the flow assurance
in the existing technology. But when that starts to
change, it will challenge us technically on how to
continue to exploit the heavier oil in the absence of
those types of [indisc.].
2:54:35 PM
CO-CHAIR GATTO said some people like to burn number 1 diesel in
their trucks and use an additive to prevent gelling. He asked
if gelling is caused by the paraffin.
2:54:42 PM
MR. TAYLOR said they are similar events in that gelling prevents
the flow of a liquid. Paraffin does create a higher viscosity
and inhibits flow at various temperatures. It is not the same
phenomenon but similar.
2:54:58 PM
CO-CHAIR GATTO pointed some of those additives make things that
aren't supposed to flow, flow.
MR. TAYLOR said that is accurate. Those products are very
expensive and cause those resources to come at a higher cost.
2:55:28 PM
CO-CHAIR GATTO asked, "Can you recover them at the other end,
where it warms up when they load them aboard a ship and the ship
is heading to warmer waters or are they just gone forever?"
2:55:38 PM
MR. TAYLOR replied they typically can be and are recovered in
the refinery process. He explained in the case of Alberta and
the North Slope, those crude oils are marketed at various
refinery locations. The degree of added complexity to the
products requires consideration of how the refineries can accept
those products. If the refineries need to buy and the
processing of crude slate costs an additional dollar that crude
will sell for a discounted price. Therefore, it not only comes
at a higher cost, it typically has a discounted value at the
wellhead.
2:56:31 PM
REPRESENTATIVE WILSON asked Mr. Taylor to go through the
ConocoPhillips' thinking process when planning for future mixing
of heavy oil with light oil.
2:57:21 PM
MR. TAYLOR told members a tremendous amount of planning is
necessary. As an investor, ConocoPhillips prioritizes its
existing producing assets. He assured members it is not part of
the thought process to inventory producible crude oil or natural
gas, although ConocoPhillips does require responsible reservoir
management. It is not advantageous to take gas from a reservoir
at the expense of the oil. As assets like heavy or viscous oil
start to come to light, the impact to flow lines, pumps and the
composition of the crude in TAPS must be considered. All of
those challenges require ConocoPhillips to anticipate various
thresholds of complexity and investment that must be tackled
before those products arrive. ConocoPhillips believes the
capacity of the current system has room for substantial growth
with current technology. However, if volumes decline, the cold
temperatures associated with the flow lines will create
different pour points and challenge the flow of the crude oil.
Those factors will require more technical analysis and
solutions, which typically come at a higher price. He repeated
he is not saying the viscous or heavy oil is not "doable," but
it is challenged. He described some of the challenges
ConocoPhillips is facing at West Sak and said this higher price
environment is encouraging new methods. He noted ConocoPhillips
plans well in advance, so repeated changes to tax policy raise
the risk of taking steps to make a project economic that might
take several years.
3:00:45 PM
REPRESENTATIVE WILSON asked if ConocoPhillips is using the
bright water technique mentioned by BP.
3:00:57 PM
MR. TAYLOR told members ConocoPhillips participates in the
Prudhoe Bay field. He said as an engineer who has worked in a
lot of older oil fields, the pursuit of altering water
channeling is something ConocoPhillips has pursued for many,
many years. He said he shares BP's excitement that they may
have found a very good application in a particular reservoir.
ConocoPhillips would like to think it will have applications in
other places too.
3:01:50 PM
CO-CHAIR JOHNSON referred to a previous slide about dilution
with Kuparuk production and asked if the Kuparuk oil is injected
into the well for recovery and whether 100 percent of the
injected oil is recovered.
3:02:28 PM
MR. TAYLOR said that oil is not injected. He explained the
intent of that table is represented by Slide 11. He stated the
dilution occurs above ground and it all goes into the same
production facility. He said while ConocoPhillips is challenged
with costs, it is doing everything possible to leverage its
current investments. He said it would be virtually impossible
to separate the two.
CO-CHAIR JOHNSON said he wanted to be sure oil was not being
reinjected.
3:03:48 PM
MR. TAYLOR continued his presentation:
Okay, carrying on, I bring this slide up [Slide 12]
only to revisit some of the testimony ConocoPhillips
had made previously and also in an attempt to try to
be more specific. I know when we come in here we talk
about information; we talk about generalizations and
concepts. It can be frustrating that we're not
talking about real numbers. What we've tried to do is
bring some real numbers in a generic way that makes it
easier to talk about something that reflects our
viewpoint.
What this slide is the column on the left represents
the state's consultants' characterization that I think
you may have seen in previous testimony of some of the
field simulations they've done on various fiscal
regimes and the calculations that went into it. What
we have done is we laid some real projects that we
have in our current decision making process. These
are real projects I'm discussing with my boss and
others as to how and when and if we'll sanction these
projects.
Some of the attributes that I'd like to point out -
first of all is the reserves side. If you go down and
look at the - about the middle column that starts at
80 and works its way across and totals to 250 million
barrels, the average reserve size is not large but yet
they are somewhat significant. I would venture to say
that they are maybe below some of the threshold of new
field economics but they are projects we are in hot
pursuit of. They are those that we want to do. A
majority of these are viscous or heavy oil type
projects.
The other thing I'll draw your attention to is the
capital per barrel is higher and you can see that
there's upwards of $4 billion or something that
resembles a $16 to $20 per barrel investment as
opposed to $11 per barrel that was illustrated in
simulation.
The other thing I'd point out is it comes at a higher
operating cost and you can see that the conventional -
or the simulation was done at $7 a barrel and let's
say the weighted average here without doing the
calculation, it's going to be higher than that. But,
much of what I described in the previous slides are
trying to be represented in this slide is, there are
higher upfront costs and there are higher ongoing
operating costs associated with much of the potential
remains.
But in the aggregate, there are significant reserves.
They need to be addressed and brought to light and
that's what we're trying to accomplish here.
3:06:18 PM
CO-CHAIR GATTO asked, assuming a 15 percent recovery for heavy
oil, whether the 258 million barrels he referred to represents
the 15 percent recoverable oil.
3:06:31 PM
MR. TAYLOR said that is correct. He explained:
I think the previous testimony, as well as numbers
that I would use here, you know, a 10 percent to 15
percent recovery with the total resource potential we
saw as being 26 billion, could be 3 billion plus or
minus barrels that will be recovered at a much higher
cost over a longer period of time but still represents
a significant target. It's 50 percent more than some
of the conventional oil reserves that exist in Prudhoe
Bay today.
3:07:08 PM
CO-CHAIR JOHNSON asked Mr. Taylor to clarify the hypothetical
projects versus the actual projects.
3:07:38 PM
MR. TAYLOR said the numbers are from clearly defined projects
that ConocoPhillips is trying to make investment decisions on.
Project 1 is a conventional oil project that could be
characterized as an improved recovery project - how to handle
the ever growing volumes of water. In the combined Kuparuk and
Alpine area, ConocoPhillips is producing 280,000 barrels per
day, which comes with more than 650,000 barrels of water every
day. Overall, for the 280,000 barrels of oil produced, 1
million barrels of water are handled everyday.
3:08:41 PM
CO-CHAIR JOHNSON asked if the expenses on the chart include
taxes.
3:09:06 PM
MR. TAYLOR said those are the lease operating costs only. The
total combined state take that could result from the six
projects on an undiscounted basis could be as high as $6
billion, as stated in previous testimony. Significant taxes and
royalties come with projects like this. ConocoPhillips believes
in the net system as the state is also an investor and that is
the correct alignment. With that comes the royalty, which can
happen immediately after a project is enabled.
3:09:49 PM
REPRESENTATIVE SEATON said committee members have continually
been told that those [projects] that are on the bubble might be
changed or might not go forward at this time. The economists
have told the Legislature that adding state participation of 2.5
percent on capital costs and adding 2.5 percent on operating
costs can aid a marginally profitable project. He ascertained
that Mr. Taylor said do not allow us more capital deductions and
questioned why that would not improve the margin for sanctioning
a project.
3:10:55 PM
MR. TAYLOR told members ConocoPhillips is in favor of a net tax
system: the deductibility of lease operating and capital costs.
That would help project economics. Without that, the projects
that ConocoPhillips is trying to find ways to reduce costs on
and increase recovery from would be further challenged by tax
changes. ConocoPhillips does favor deductible costs. Tax
changes affect planning because with an inventory of projects;
those "on the bubble" go back and forth, depending on whether
they are impaired by technology, taxes, or costs.
3:11:56 PM
REPRESENTATIVE SEATON inquired:
So, other than, let's say, the gross floor, which has
pretty much fallen off the table in the bill that we
have before us now I mean on project 4 there, by us
adding another $500 million into your capital
deduction, in other words the state picking up that
and adding 2.5 percent of the expense - I didn't
calculate that one out but that's about one third of
that. How does that not enhance your ability to
sanction that project?
3:12:39 PM
MR. TAYLOR said those attributes do enhance those projects. He
said he has prepared some comments related to the proposed
legislation and this segues into a discussion about the gross
progressivity.
3:12:56 PM
REPRESENTATIVE SEATON replied:
Rather than get on that I'd like to drill down into
this first because the difference between 22.5 percent
net tax and 25 percent net tax is 2.5 percent that we
allow you to deduct - or we increase our participation
in your costs of capital and we increase our
participation by almost 10 percent in the
deductibility of the expenses. All the economists
that we've talked to, whether Pedro Van Meurs or
others, they cautioned about what percentages because
the state's risk goes up because we participate more
in these very expensive projects that if on the
margins are not very profitable, you don't tax much
but our increase in liability for additional cost
sharing goes up significantly. So, I'm constantly
having this problem of industry coming in and saying
that this is a detriment when $500 million for
projects for capital costs - and I guess that's about
$1.5 billion more in the expense column there -
according to the economists that are testifying to us,
it actually makes those projects - it goes from either
non-economic to marginal or marginal to viable. So if
you can explain that to me I'd appreciate it.
3:14:28 PM
MR. MITCHELL explained that it amounts to the timing of the cash
flows and how much upfront investment is subject to that
deduction and credit and, once a project is operational, how
much of a margin is subject to the higher tax level. He said
with some projects the upfront investment benefit could exceed
the value of the additional tax once the project is producing.
He said that will not apply to every project but Representative
Seaton's point is valid because some projects will benefit more
from the upfront deduction.
3:15:44 PM
REPRESENTATIVE SEATON said the disconnect he is hearing is that
the oil companies say marginal projects will fall off when, in
reality, marginal projects will be aided and made less marginal
by the increase. He pointed out the tax rate is applied across
the entire company's profit but the tax rate applied to marginal
projects enhances their viability.
3:16:52 PM
MR. TAYLOR said the net tax system will encourage some
investments. Once the PPT passed, the industry stabilized and
looked at their projects, reloaded and moved forward. The
difference between a 22.5 versus 25 percent tax rate will not
destroy every single project. It will have an "erosional effect"
on some of the marginal projects at 22.5 percent. They would be
less productive at 25 percent.
3:17:47 PM
REPRESENTATIVE SEATON asked Mr. Taylor to pencil it out for him
later.
3:19:01 PM
MR. TAYLOR reemphasized that in 2016, 42 percent of the
production shown by DOR will come from existing fields. Those
are incremental investments. As ConocoPhillips starts to make
those investment decisions, factors that alter the economics
associated with those choices will have a direct impact on
ConocoPhillips' ability to fight that decline. It will not
eliminate all of the projects but will take away from the
economic viability of some of them that could fight the decline.
He continued:
It's not about the overall tax of existing assets. It
may be a mathematical exercise - is 25 percent of this
amount of production going to generate more state
revenues than 22.5 percent, let's say, of this wedge,
which is really part of the analogy that's trying to
be brought to light here. Industry is saying that
altering costs and altering risk alter our decisions
about the incremental project - the new project. And
what we're trying to advocate here is upwards of 40
percent of the future in as little as 8 years from now
will come from those new investments.
3:20:40 PM
REPRESENTATIVE SEATON said he can understand that on a company-
wide profitability basis but industry says marginal projects
will lose. He said Mr. Taylor is saying high profit projects
without the large proportional costs will be impacted the most
but marginal projects with lower profitability and higher costs
will be aided and made less marginal by the 2.5 percent. He
asked Mr. Taylor to prepare a flowchart that shows the influence
of the 2.5 percent tax difference on a marginal project for
committee members.
3:21:59 PM
MR. TAYLOR offered to provide feedback on that but clarified
that it is the high cost, high investment project that will be
on the bubble of marginal economics and will be impacted.
3:22:30 PM
REPRESENTATIVE ROSES echoed Representative Seaton's concerns.
He commented in terms of the credits, he planned to build three
car washes and gas stations over three years but decided to
build all three in one year when the federal government offered
investment credits on equipment. The credits allowed him to
capture 10 percent of all of the equipment costs and he could
escalate the depreciation. His investment decision was changed
because of tax structures. He felt Representative Seaton was
trying to convey that some of the incentives offered by the
state will make some of the marginal projects less expensive in
terms of the oil companies' capitalization because the state
will be taking a proportional share of it.
3:24:15 PM
REPRESENTATIVE GUTTENBERG indicated that members are talking
about increasing credits for capital investment and the
difference of 2.5 percent. The price of oil has jumped from $70
to $100 per barrel. It could jump to $130. At that point, he
cannot see that difference be anywhere near as significant as
the change in cost. He felt the price increase would have a
much higher influence [on investment decisions] than a 2.5
percent tax increase when the state is increasing its
involvement.
3:25:13 PM
MR. TAYLOR replied the elements of progressivity and tax were
introduced in PPT. But now the talk is about doing something in
addition to that. He is saying anything that is done in
addition can have erosional effects on some of those decisions
that ConocoPhillips has contemplated. He believes some of the
expectations set out in terms of changing the tax that resulted
in PPT have been met. The revenues have increased. The
question now is whether that was the intent or should it again
be changed. He repeated that taking additional steps will
always erode the economics of what is on ConocoPhillips' slate.
He emphasized that each step the state takes has an additional
erosional effect. He said the concepts behind the net tax
system are helpful in ConocoPhillips' planning process. He
continued:
Of course, the question in front of us here today, and
what's being discussed - do we need to take additional
steps beyond what PPT had established. I think what
we're trying to say is that if you do raise tax beyond
what's in the current law that will have an erosional
effect. Is it totally destructional? No. Does it
start to push other projects further out or those that
were marginal with PPT at a higher tax rate - will
they become marginal? Yes. That line goes up and
down as we change the impacts of costs. That was the
intention.
3:27:36 PM
MR. TAYLOR turned the presentation over to Kevin Mitchell.
3:27:52 PM
MR. MITCHELL told members his comments would be specific to the
contents of the committee substitute bill, which contains the
22.5 percent PPT rate but replaces the progressivity from PPT to
a gross base progressivity.
3:28:45 PM
MR. MITCHELL began his presentation:
In the draft bill that we have in front of us today,
the progressivity, which in PPT was a net based
progressivity - just as a reminder that progressivity
kicked in at a $40 per barrel net margin, if you like,
and escalated at a rate of .25 percent per increase
over that $40 threshold.
In this bill, that progressivity has been removed.
The base rate is still the same as PPT at 22.5 percent
but that net progressivity has been removed and has
been replaced by a gross progressivity, which triggers
at a $50 per barrel net back price and then escalates
at a .225 percent increase above that.
What we find as we look at the impact of really any
tax on the gross, what that does is give the ... it
puts the biggest challenges on the projects that are
the most challenged in the first place, and we see a
lot of those out there in terms of where the future
development potential is. Those are the very projects
that suffer the most from that. The reason for that
is the fact that they are the most challenged is
saying they are the highest cost projects and so the
margin that's left to play with is squeezed more for
those projects than any of the more attractive
projects. By taking a slice out of the gross, what
that's doing is reducing the revenue that would
otherwise be available to cover those higher costs.
And then, specifically with a gross progressivity that
has a trigger point with no indexation in it, and the
reality is the costs will rise over time, eventually
you could get to a point where there's a progressive
tax coming out of a revenue stream that really is -
all it's doing is covering costs. We can see that
could happen over time.
3:30:46 PM
With the net system that we have today, it really
works in all situations because the most profitable
areas get hit with a very sizeable tax percentage. So
in the current environment, for example, where we are
dealing with high prices, and yet we've made a lot of
statements that costs follow prices, which over time
there's a lot of evidence to say that does happen but
we fully accept that costs haven't risen over the last
three months to the same extent that the prices have
risen, so there has been a significant expansion of
that margin that's available.
But with the PPT progressivity that we have, at
current prices that's probably something like a 28 to
29 percent tax rate that's being applied to that
marginal [indisc.] so in many ways it behaves like a
high rate gross system and yet, at the same time, the
more challenged projects are adjusted because that
calculation is based on the net. And so, it really
works. The PPT type net structure - it fits all sizes
a lot better than whenever you introduce a gross
component, there are certain areas that will get
really disadvantaged by that. Actually I think the
Administration has been a very strong advocate of
retaining the tax structure on a net basis.
3:32:35 PM
REPRESENTATIVE ROSES agreed the Administration has supported the
net progressivity but it has also pushed for a 10 percent floor
on the lower end. The Administration has also approached
removing some of the credits that this bill put back in. One
reason the progressivity was included was to offset some of the
other changes. As the price escalates, the higher expenses can
be deducted at the initial base tax rate of 22.5 percent. He
surmised the question becomes where does the progressivity on
the gross offset what a company would get on the base.
3:33:33 PM
MR. MITCHELL replied the difficulty he has with the floor is
that the 10 percent floor hurts at the very time you don't want
to hurt investment. That could occur in a low price environment
where a fixed percentage is taken from the gross. That becomes
a very progressive feature from a tax perspective. However, in
those environments with opportunity for significant investment,
the floor can be triggered by high investment levels because the
calculation is based on the higher of the PPT net or the floor.
He explained:
And if you're progressing some of these projects, a
significant amount of investment activity going on,
that can be enough in itself - it triggers the floor,
which thereby removes the investment incentives, the
deductions and the credits and turns you back to
projects that no longer look as attractive. And so
that's the difficulty we have with the floor is that
it hurts you both in a low price environment but also
when you've got potential significant investments
ahead of you, which is why we come back to really the
net works in all environments. It does mean if you
stick with a purely net system, there's no doubt there
are situations where it means the state has more
downside risk. The floor reduces the downside risk
for the state but it doesn't get impacted by the
investment potential.
3:35:32 PM
CO-CHAIR GATTO asserted, "That floor will so change the State of
Alaska we'll be worrying about a lot more than did we lose our
10 percent at these low oil prices."
3:35:40 PM
REPRESENTATIVE WILSON said she hears Mr. Mitchell saying the net
tax will go up and down with any and all projects. However,
with a gross tax and oil company would have to pay more so the
state could lose out because the oil company might decide not to
do a project that is right on the line.
3:36:33 PM
MR. MITCHELL said that is correct. Some projects might not
happen because of the existence of the 10 percent gross tax.
The net tax reflects both the revenues and costs of development
so it becomes self adjusting and reduces the likelihood that
this topic will need to be revisited again in the near future.
Generally net tax structures are more sustainable than gross
structures.
3:37:18 PM
REPRESENTATIVE WILSON asked how legislators can assure their
constituents that the state is getting its fair share with a net
tax.
3:37:49 PM
MR. MITCHELL expressed his belief that it comes down to the
alignment between industry and the state. The net tax will
provide more incentive to move forward with some of the more
challenged projects. That is good for both parties because
economic projects generate taxes and royalties. He reminded
members the 12.5 percent royalty comes off the top anyway.
3:38:41 PM
MR. TAYLOR added another consideration is that investment
fosters secondary and tertiary benefits to the local economies,
whether that is in the form of employment or goods and services.
3:39:52 PM
REPRESENTATIVE SEATON questioned whether the problem is not the
progressivity tax itself but rather the gross trigger under the
current bill because projects with different cost structures
would be taxed equally. If the trigger is adjustable on the net
profit or the margin of a field that would be the actual factor
that makes the previous tax work better, rather than the
structure of the tax itself.
3:41:05 PM
MR. MITCHELL said yes. What ConocoPhillips likes about the PPT
structure with its progressivity is that the trigger point is on
a net basis so there must be a profit component before any
progressivity is applied. The progressivity calculation is then
based on the expansion of that margin, not just the expansion of
revenue. Under the proposal in the committee substitute, all of
the progressivity is on a gross basis.
3:41:54 PM
REPRESENTATIVE SEATON surmised that Mr. Mitchell is concerned
that one of the components of the current bill's "gross tax"
section is keyed strictly to price and not to the economics of
the field. ConocoPhillips is less concerned about the
deductibility of the tax itself than it is about it being keyed
to the margin of the field so it takes place when the economics
of a field reaches that point.
MR. MITCHELL concurred, adding that in such a scenario it is a
mutual benefit that "we're not paying that tax when we're not
making ... a margin."
REPRESENTATIVE SEATON remarked the Legislature is worried about
revenue and about the financial risk to the state. The problem
is that a net tax on a "net trigger" means that a high rate of
tax also becomes deductible. Therefore, if the progressivity
caps out at 25 percent under any of the scenarios, if left as a
net tax, the state would be contributing another 25 percent to
the capital and operating expenses of the projects. He said he
would be willing to "key" the tax to the margin and have that
float with the net tax but asserted, "I am definitely thinking
that we've provided enough in 22.5 or 25 percent tax
deductibility plus credits, without making the progressivity
also a deductible item." Making it "key to the margin,"
Representative Seaton posited, would cure Mr. Mitchell's main
objection to the progressivity.
MR. MITCHELL concurred.
3:44:50 PM
MR. MITCHELL continued his presentation:
So we've probably actually beaten this subject to
death. We did have another slide in here that talks
about the impact of progressivity on the gross. We
probably have really covered all of these points that
these examples - and these are just generic examples
that say when you have a low cost project, depending
on what price assumption you have out there, the tax
paid is going to be split between the base net share
and then the amount that is driven by the
progressivity. In a higher cost project, you could
envision a scenario where assuming a reasonable price
environment and not a complete blow-out in prices, you
could imagine a scenario where there really is no net
margin and, in fact, there's a tax coming out of the
gross, which is making the overall project look
uneconomic. I think we really covered all of these
points in the last few minutes of discussion.
CO-CHAIR GATTO asked Mr. Mitchell if he is about to transition
his presentation into TIE credits.
MR. MITCHELL said he is.
CO-CHAIR GATTO announced the committee would take a 10-minute
break.
CO-CHAIR GATTO gaveled the meeting back to order at 4:10 p.m.
MR. MITCHELL continued with his presentation:
What I'd like to do now is talk a little bit about the
transitional investment expenditure (TIE) credits,
which we recognize that in this version of the bill,
they were - some form of TIE credits was added back
compared to what was in the original bill that the
Administration had produced. However, they weren't
added back to the full extent of how they were
included under PPT.
The key point on the transitional, or the TIE credits,
is that the companies that are impacted by removing
those TIE credits are those companies who one, were
investing in the past and two, were investing in the
future. It requires that historic investment and
future investment in order to capture any value
associated with the TIE credits and so - and
ConocoPhillips has been a consistent investor in
Alaska and we plan to continue - we are continuing our
investment and when you look at some of the examples
that actually you could draw a scenario that says we
might have been better off having not advanced those
projects when we did but delaying them, which really
isn't ultimately in anyone's - it's not what any of us
want ... to look at that. But it's those investors,
historic and future, that stand to lose by the removal
of the TIE credits, which - that's the very reason
they were put into the PPT in the first place.
The TIE credits do serve to soften the impact of tax
changes and it does have a finite - that provision has
a finite life on it. It's not an ongoing component of
the tax legislation but it does come to end - by 2013
is the limit by which you can use up those available
TIE credits.
4:12:55 PM
MR. MITCHELL continued:
Moving on, I did want to talk a little bit about some
of the exclusions and deductions from allowable
expenditures that are included - that are part of this
bill. The topping plant has had some discussion
previously and my main point on the topping plant is
whichever way you look at it, that plant is an
integral part of our operations to generate diesel
fuel for use in lease operations and to take that one
asset and isolate it and say we're actually going to
treat that asset different for tax purposes. To me it
goes against good sound tax practice and it adds
complexity. With any kind of a net system, the system
will operate best with a straightforward, if it's a
cost of operations then it's an allowable - if it's a
leasehold operating cost then it's an allowable
deduction and by taking a particular piece of that
plant and saying we're going to treat that differently
just kind of adds some complexity and confusion to the
overall structure. I recognize there are concerns
around the project, which is that the [ultra-low
sulfur diesel] ULSD project on that - and understand
those concerns around that but nonetheless, just the
exclusion of a particular piece of the operation just
doesn't feel quite right in the context of what is a
net tax structure.
4:14:41 PM
CO-CHAIR GATTO questioned how it adds to the complexity and the
confusion.
4:14:51 PM
MR. MITCHELL explained the ongoing costs of operating that
particular plant are not allowable deductions while the ongoing
costs of operating everything else are allowable. That requires
segregating out the costs of the plant. A formula allows for
that but the fact that one piece must be segregated out and not
included creates complexity.
4:15:42 PM
CO-CHAIR GATTO said he thought that system would be less complex
because those particular costs would be ignored.
4:15:58 PM
MR. MITCHELL said his view is that unit is integral to
ConocoPhillips' operations. Some of the costs associated with
its operations are potentially shared with other areas. It is
more difficult to segregate those costs out than to add them in
because those costs are already included in the total.
4:16:33 PM
REPRESENTATIVE WILSON asked Mr. Mitchell if ConocoPhillips wants
to treat the topping plant like the rest, whether the
Legislature should charge royalties and the PPT so that
everything is charged the same.
4:17:20 PM
MR. MITCHELL told members the costs of the existing topping
plant are included in the PPT as an operating expense.
Therefore, to exclude that now and replace it with another
formula adds complexity. The crude oil used at that topping
plant to manufacture diesel, assuming that diesel is consumed in
lease operations, would not be subject to royalty or tax
payments. However, on the flip side, if ConocoPhillips does not
provide its own product and purchases it instead, then the value
of the purchased product becomes a deduction against tax.
4:18:26 PM
REPRESENTATIVE WILSON asked how much production will increase.
4:18:56 PM
MR. MITCHELL clarified that Prudhoe Bay has its own diesel
making plant, as does Kuparuk. The proposed project would be
one plant that would serve both Prudhoe Bay and Kuparuk. The
combined facility would not create an incremental volume
[increase]. He stated, "For the plant at Kuparuk it's
additional, but that's to be able to provide the use for Prudhoe
Bay as well.
4:19:36 PM
REPRESENTATIVE WILSON said she assumed, from previous testimony,
that ConocoPhillips would be able to sell diesel to some of the
explorers and other companies.
4:19:51 PM
MR. MITCHELL said that is correct; it will be able to provide
ultra low sulfur diesel for Slope-wide use. To the extent it
isn't used in ConocoPhillips own operations, it would be subject
to royalty and tax.
4:20:12 PM
REPRESENTATIVE WILSON acknowledged the project is relatively
small now but could mushroom into something big. She expressed
concern about the amount the state would lose if that happened.
4:20:23 PM
MR. MITCHELL said it should not mushroom into anything beyond
the sum of what is available today. The Kuparuk facility would
be larger but it would replace some of the diesel production
taking place at Prudhoe today.
4:20:52 PM
MR. TAYLOR added:
If you think of the logistical complexity of what we
would have to do if it was not manufactured on site -
on site it would be a construction project that would
be for the beneficial use of the lease. It's designed
to meet the EPA [Environmental Protection Agency] and
ADEC [Department of Environmental Conservation]
requirements for road applications. So there is
current diesel that's being manufactured now and it's
being manufactured on the lease for the benefit of the
lease in the local area.
If we were not to build a plant of ULSD on the Slope,
then the logistics that would be behind it is that
crude oil would be produced down the pipeline, be
picked up by a boat, be taken to a refinery somewhere,
then remanufactured into ULSD and then have to be
transported back up to the Slope to be used on the
Slope. So all that seems to add additional costs and
inefficiencies when it's our opinion it would be more
efficient to be done locally and that it is a
beneficial use of the lease and it is a lease cost
associated with it. So, that's the thinking that
we're applying to it.
Some of the added risks I think were alluded to this
morning were that depending on what that
transportation would look like, whether it's rail up
to Fairbanks and then trucked on the Haul Road up to
the Slope that that starts to add some risk associated
with derailment or roll over or some potential risk
associated with the environment. So that's another
added attribute of consideration.
It's not the sole determining factor but those are
some of the complications that go through our minds
when we think about doing something locally, something
for the benefit of the lease to meet those
environmental requirements as opposed to going through
the tortuous process of taking it from the Slope,
taking it to a refinery and then bringing it back.
4:22:46 PM
CO-CHAIR GATTO asked if ConocoPhillips currently produces all of
the diesel needed and more or whether the amount it is producing
does not satisfy the requirement.
4:23:07 PM
MR. TAYLOR answered he does not know whether any surplus is
produced, but he noted the ULSD project is designed with local
use in mind. Its design capacity is 2800 barrels of diesel per
day, which is broken down into 1,000 barrels per day for use in
the greater Prudhoe Bay area and 700 barrels per day for
Kuparuk. The remainder would be used for rigs and contractor
support. To the extent available, it could be supplied to local
communities for heating fuel.
4:23:58 PM
CO-CHAIR GATTO said he is curious about whether independents and
others would have equal access or whether diesel would be
rationed until the three major producers' demand is satisfied.
4:24:18 PM
MR. TAYLOR responded his project engineers and economists have
informed him the 1,000 barrels a day is designed for Prudhoe Bay
demand and 700 for the Kuparuk area and the balance is for the
independents, contractors, and to support lease operations, and
could be made available to others at the local market price.
4:24:50 PM
CO-CHAIR GATTO asked if a competitor would suffer an economic
penalty when buying that diesel.
4:25:24 PM
MR. TAYLOR said ConocoPhillips' intent is to design a plant for
the beneficial use of the lease and provide a competitive local
market price, not to create a situation that would gauge anyone
inequitably.
CO-CHAIR GATTO asked if a competitive local price means it would
be competing with a Fairbanks manufacturer who is trucking it to
a facility.
MR. TAYLOR believed local market determination would involve
factors like that as well as associated manufacturing costs.
4:26:08 PM
CO-CHAIR GATTO asked if ConocoPhillips pays federal or state
fuel taxes on the diesel it produces and consumes.
4:26:17 PM
MR. MITCHELL said he would need to look into that.
4:26:26 PM
REPRESENTATIVE SEATON said he doesn't believe anyone opposes
building a plant; the question is whether the state should
subsidize it with credits. He asked at what point
ConocoPhillips is taking capital credits and deductions on
refinery module expenses and when they reflect on PPT.
4:27:46 PM
MR. MITCHELL said ConocoPhillips would recognize those charges
as they are incurred. That is the case for all expenses -
operating and capital.
4:28:18 PM
REPRESENTATIVE SEATON recalled that the committee previously
discussed this issue to ensure that the state is not financing
[refinery modules] built in Korea, Japan or Alabama and then
having those capital credits and expenses deducted "when the
units reached Alaska." He expressed concern that Mr. Mitchell
has testified that if the tax structure changes and the capital
credits are not issued, the plant might not be built. He asked
at what point, since the capital credits have already been
taken, ConocoPhillips might say it no longer plans to build the
plant or decides to delay its construction for many years.
MR. MITCHELL responded:
We recognize the credits, the expenditure, when we are
incurring it. Now, if there's ... rules that limit
the timing of when you can do that - if the PPT or tax
legislation defines specific rules around when you can
do that - then we will do it in accordance with those
rules.
By having incurred the expenditure, he remarked, by definition,
the company is proceeding with the project.
REPRESENTATIVE SEATON relayed that legislators have heard that
if the state doesn't "give the tax credits," ConocoPhillips may
not build that plant even though the capital credits and
deductions have already been taken. Nothing in the current
bill, he surmised, stipulates when a company must make a
decision regarding whether to proceed with a project. At what
point, he asked, would ConocoPhillips Alaska, Inc., say it's not
going to build a plant and thus require a tax credit refund. He
stated the citizens of Alaska are worried about "getting gamed"
on the net system. Therefore, he pondered, wouldn't the state
be better off by ensuring that the Capex doesn't get deducted
until it reaches Alaska.
MR. MITCHELL indicated that concern ought to be alleviated by
the fact that ConocoPhillips Alaska, Inc., has neither committed
to incurring, nor has incurred, the expenditure for the "hydro-
treater," which would remove the sulfur. He acknowledged,
though, that other expenditures have been incurred to scope and
work the project. He added, "We typically would not be in a
situation where we're spending those dollars, claiming it on a
PPT return, and then deciding we're not going to go ahead with
it. At that point we're well sunk, if you like, into that
project."
REPRESENTATIVE SEATON reiterated that Alaskans are simply
concerned about the possibility that companies will game the
system, and that's why the Legislature may need to tighten the
statute in that regard.
4:34:51 PM
REPRESENTATIVE ROSES asked whether state and federal taxes are
paid on the diesel being produced and whether EPA is requiring
low sulfur diesel be used for industrial applications only or
for all purposes, including home heating.
4:35:37 PM
MR. TAYLOR said his understanding is that EPA regulations are
focused on road use.
4:35:52 PM
REPRESENTATIVE ROSES asked whether the two plants that cannot
produce low sulfur diesel will be dismantled or whether they
could be used to produce excess [diesel] for local communities.
4:36:20 PM
MR. TAYLOR thought ConocoPhillips would continue to operate
those plants to the extent that normal diesel can be used and
has a beneficial use on the lease. He pointed out taxes would
be paid on any sales transactions.
4:37:09 PM
REPRESENTATIVE ROSES said he would hate to see the existing
plants be abandoned when they could be used for an alternative
purpose.
4:37:25 PM
MR. TAYLOR said ConocoPhillips would maximize the use of its
preexisting investments to the extent possible.
4:37:38 PM
REPRESENTATIVE ROSES asked whether the plant has a remaining
life expectancy.
4:37:56 PM
MR. TAYLOR said he does not know how many years of use are left
on the existing plants but, to the extent they are economically
viable and there is beneficial use on the lease or to the local
market, that should be addressed on an ongoing basis.
4:38:23 PM
CO-CHAIR GATTO acknowledged at some point the plants will have
to be replaced and replacing them sooner provides the advantage
of producing low sulfur diesel. However, it would be
advantageous to know the remaining life span.
4:39:26 PM
MR. TAYLOR said, for the record, this project is in a state of
sanctioning for ConocoPhillips Alaska, Inc. and its partners.
ConocoPhillips is on hold with logistical plans to continue to
meet EPA and ADEC requirements for ULSD use. The project is in
a design phase to where it could go forward for sanctioning but
it has not invested substantial dollars so that it could claim
any credits. The sanction decision must be made before the
state chooses whether deductions can be taken.
4:40:30 PM
CO-CHAIR GATTO asked if the incurred charges have been charged
as operating expenses.
4:40:37 PM
MR. TAYLOR said most of those charges have entailed ongoing
engineering and design costs, which is the normal practice for
all operating expenses on any project for technical staff.
4:40:56 PM
REPRESENTATIVE SEATON said he has heard shipping companies say
60 or 200 trucks are loaded and waiting to come up from Seattle
[with supplies for] this plant but were put on hold. He asked
if that is true.
4:41:47 PM
MR. TAYLOR said he was not aware of that. ConocoPhillips has
not expended substantial capital outlays on the project. He
said it is possible that a procurement process or sourcing of
materials may have occurred.
4:42:16 PM
MR. MITCHELL continued with his presentation:
The other item we wanted to touch on in the context of
exclusions or expenditures to be excluded as allowable
costs is the language that's in this draft bill on
unscheduled maintenance or maintenance that causes
unscheduled production interruptions and the way that
language is worded. Let me just back up and say we
understand the event that triggered the dialog around
that and we understand there's something that needs to
be addressed through this but the way that language is
laid out, it is very broad and all encompassing and,
in reality, would be very difficult to actually
administer and audit, even with the additional audit
resources that the Department of Revenue is trying to
secure through this process. I still think that
particular area will be very difficult for all of us
to ensure this full compliance with. It's a
combination - it's not just an accounting. This is
not just a financial audit type of matter. It gets to
the heart of the nature of production operations and
all the various things that go on that can have an
impact on our day-to-day operations, which can follow
all of the normal, sound operating practices, the
recommended maintenance activity and yet still there
will be things that happen that weren't planned. It
will be very difficult to not only identify those
specific events, but at the same time keep track of
what's the specific cost of that event so that we
exclude it from the PPT computation. It kind of - to
me it's the sledge hammer to crack a nut solution and
if we go on to the next page, we potentially can see
what we're dealing with here.
4:44:34 PM
What this chart represents is daily production for the
Kuparuk area from December 2006 through to pretty much
current. And there's nothing smooth whatsoever about
that line and if you trend it out and actually do a
monthly average and draw that line on a monthly
average, it probably would look reasonably smooth with
a couple of specific spikes or dips for specific
events. When you look at that it then becomes on a
daily basis it is very difficult to step back and
identify specifically which of those events that were
a function of unscheduled down time and what were the
costs associated with that specific event.
I think when the PPT legislation was put into place,
there was the 30 cent per barrel reduction, if you
like, was factored in for some of this. It's never
been entirely clear to me exactly what the intention
was of that but there is that reduction in the
deduction, if you like. And at the same time, in this
latest version of the bill, I think it's subsection
(6) of this relevant section talks about disallowing
costs associated with violation of law, failure to
comply and so on, so there already is a compliance
type standard elsewhere in the bill and the piece that
we're talking about, which is subsection (19) I think,
then becomes very broad and difficult to administer
and so I think our comment around that is it's just
something that we need to be very careful how we put
that into law because the way it's worded it just
appears to be fraught with difficulties in making sure
that we're compliant and the state is capable of
ensuring that we're complying through the audit
process.
4:46:42 PM
REPRESENTATIVE SEATON asked if Mr. Mitchell would be amenable to
deleting [proposed AS 43.55.165(e)(19)] and changing [proposed
AS 43.55.165(e)(6)] to ensure that expenses related to a
recovery from criminal negligence were not allowed as a lease
expense.
MR. MITCHELL indicated that solution would be preferable to what
is currently in the bill.
4:48:04 PM
MR. MITCHELL continued his presentation:
[Slide 19] I think we just have a couple of other
points that are really not that significant but just
wanted to mention. In terms of information sharing,
there's a sort of catch-all phrase that provides the
Administration with the ability to request any other
information it considers necessary and I just feel
it's very broad to have that broad brush any other and
there's always going to be some element of concern
where we're subject to that very broad requirement.
We understand ultimately where the Department of
Revenue - what they're trying to accomplish in terms
of having the right data to do what they need to do
and we're supportive of that. This catch-all gives us
a little bit of concern because of the breadth of it.
4:49:01 PM
REPRESENTATIVE SEATON asked for suggested wording to narrow that
down and still allow DOR to get the information it needs for a
net tax system.
4:49:30 PM
MR. MITCHELL said he was sure ConocoPhillips could come up with
language that would address its concerns and provide DOR with
the level of comfort it needs.
4:49:46 PM
REPRESENTATIVE SEATON requested that ConocoPhillips Alaska, Inc.
forward its suggested language to the committee for
consideration.
CO-CHAIR GATTO added in a timely manner.
MR. MITCHELL agreed to do so.
4:50:14 PM
MR. MITCHELL continued:
The statute of limitations [Slide 20] got some
discussion this morning as well and, again, it's not
necessarily a huge item but I think it's in all of our
interests that the audit activity gets conducted
timely and extending that statute from 3 years to 6
years just gives the potential. It doesn't mean to
say it will happen. It just gives the potential that
this audit work can drag on over a longer time period
than it might need to significantly. If you take that
to its literal extreme, by 2011, the year when the PPT
legislation requires that review with a 6-year statute
of limitations, in theory that first audit might not
even be complete. So, our preference is to be able to
get this work done as quickly as possible.
Of course, from a - I have to acknowledge from an
industry perspective, we're always going to say we
prefer a shorter time on a statute so - but six years
feels like a long time to have that hanging out there.
4:51:32 PM
MR. MITCHELL continued:
So that really just leaves us with our kind of wrap
up, which actually is a repeat of how we introduce
this in terms of our key points with regard to this
bill. We do believe that there needs to be the
alignment between the state and the industry as we've
said. When industry is doing well, the state is doing
well. Projects that are economic for us are projects
that generate revenues for the state and so we really
have that common interest there. We do believe that
it's too early to change PPT in the context of
significantly changing what that tax structure looks
like. It's very early and it's unsettling having that
continual - the frequency of tax changes. In this
presentation, in terms of tax take, we really focused
our discussion around what impact the progressivity on
a pure gross basis can have and we really want to
emphasize the message that when there's any form of a
tax - production tax that comes straight out of the
gross - then it has the potential to have a
detrimental impact. The PPT, the way it's structured
with both the base rate and the progressivity on the
net, it does work. It's self adjusting. The more
challenged projects get the right kind of deduction
and relief and yet, the more profitable areas with the
progressivity still end up paying a higher percentage,
especially as you look in the current price
environment we see that percentage increase
significantly. You almost get the behavior like - on
the marginal dollar - like a high gross rate.
And then lastly, we just talked on some of the
administrative provisions. We just want to make sure
that we don't put anything into law that, with the
benefit of hindsight, we find really that wasn't what
we intended or that became somewhat unworkable so we
just encourage that the right amount of thought and
consideration go into that.
4:53:38 PM
CO-CHAIR GATTO said as partners, the state and industry both
want money. He would prefer the word "quest" be used, rather
than "aligned," which he feels is too formal.
4:54:38 PM
CO-CHAIR GATTO thanked Mr. Taylor and Mr. Mitchell for their
presentations and asked Mr. Gibson and Ms. Houle to give their
presentation to the committee.
4:58:55 PM
KURT GIBSON, Acting Deputy Director, Division of Oil & Gas,
Department of Natural Resources, introduced Julie Houle, Section
Chief for the Resource Evaluation Section in the Division of Oil
and Gas and told members they would discuss the exploration
incentive credits in AS 43.55.025, enacted in 2003. He
continued:
It preceded PPT. There were some changes to that
particular statute that were a part of the Governor's
original legislation. Those changes to the existing
statute were dropped between the bill moving from the
... House Oil and Gas Committee to House Resources and
so we just wanted to chat about why those were
appropriate in the original piece of legislation and
how we might be able to create some language that is
suitable to reinsert into the piece of existing
legislation.
We're going to talk, really kind of in broad terms,
conceptually why the language was drafted the way it
was, why the changes were made. Essentially it was
housekeeping. As I said, the statute already existed
for exploration incentive credits for explorers.
There were some, as with any rules, over the course of
time it becomes evident that there are some
shortcomings and so we just wanted to kind of sure up
that stuff and make sure that the state was receiving
proper value for the credits that it was distributing.
MS. HOULE informed members the sections were numbered 36 through
44 in the original bill as introduced.
5:01:08 PM
MR. GIBSON continued:
So, the original language intended to do the
following. It intended to broaden the existing
program to create greater credit incentive for
explorers within certain proximity and for wells
drilled within a particular timeframe. It also was
intended to provide additional predictability and
consistency for explorers in terms of whether or not
their exploration activity would qualify for these
credits. And then finally, it was intended to sure up
certain data requirements that the original statute
was not entirely effective in ensuring that the state
receive certain seismic and well data and core data
that the original legislation - to make sure that the
state received that for a number of purposes and Julie
will talk about that some as we kind of get to that
point.
5:01:57 PM
MS. HOULE told members DOR and the Division of Oil & Gas get
involved by assessing what technical data needs to be submitted
to approve an application. However, DOR approves or disapproves
the expenditures.
5:02:18 PM
MR. GIBSON continued:
So the language in the original ACES bill was intended
to broaden the existing program so that certain
exploration activity that occurred within three miles
of existing wells would receive a 30 percent tax
credit if they were drilled within a certain
particular timeframe and the original language
addressed an 18 month timeframe, as long as they were
no more recent - or rather if they were within an 18
month timeframe they would qualify for this tax
credit.
It also broadened the existing program by allowing for
five percent deduction for - or tax credit for old
seismic data that certain existing producers in Cook
Inlet and the North Slope both may have, kind of, on
their books or in the vault as Julie says, creates a
value for the state by ... attaching a tax credit to
... the cost of that activity. That data then becomes
public and it creates the ability then for new
explorers to access that data and determine whether or
not certain areas are prospective and whether or not
they want to engage in exploration activity in those
areas.
5:03:37 PM
MS. HOULE said the last bullet would extend the allotted time to
drill wells from 150 to 540 days. This would occur when a
company plans to drill several exploration wells in one season.
The wells might be less than three miles apart but are drilled
within a short time period while a rig is onsite.
5:03:57 PM
MR. GIBSON continued:
[Slide 3] So the original statute, I think, had the
unintended consequence of requiring wells to be
drilled within five months of one another, or rather I
guess it could be logically determined that the intent
was then to make it during a single drilling season
whereas an exploration may extend beyond a single
drilling season and those exploration wells may be
within three miles of one another. The intent of the
legislation is to allow those exploration wells in the
exploration program to all qualify for the exploration
incentive credit.
5:04:31 PM
REPRESENTATIVE GUTTENBERG said he worked on a seismic crew in
the early 1970s. He asked if that kind of information is
translatable to today's standards.
5:04:51 PM
MS. HOULE replied some data from that time period is still good
with reprocessing; particularly the 2-D seismic drilled for the
deeper objectives. Whether it is useable depends on the quality
and whether it can be digitized.
MR. GIBSON added the commissioner of DNR can determine whether
making that data eligible for credits is in the best interest of
the state.
5:05:24 PM
MS. HOULE clarified the seismic data could not be from an
existing unit.
5:05:34 PM
REPRESENTATIVE SEATON referred to the 20 to 30 percent expansion
and asked if that means 30 percent in addition to the 20 percent
for PPT.
5:05:44 PM
MS. HOULE told members the AS 43.55.025 exploration incentive
credit (EIC) credit was originally written to apply 20 percent
to a well drilled more than three miles [from an existing unit]
and to apply an additional 20 percent for wells drilled 25 miles
away from an existing unit. She added the credit would also
apply to seismic activity outside an existing unit.
5:06:13 PM
REPRESENTATIVE SEATON asked if the current EIC now at 30 percent
would be in addition to the PPT credit of 20 percent and in
addition to the deductibility against PPT of 25 percent under
ACES.
5:06:36 PM
MR. GIBSON said he was not sure how the mechanics of the two
pieces work but he did not believe the intent is to stack the
deductions so that the state is a 70 percent participant in the
investment. The intention of the EIC is to draw distinction to
strictly exploration activity.
5:07:07 PM
REPRESENTATIVE SEATON said he believes it previously amounted to
an additional 20 percent over the 20 percent PPT credit for a
total 40 percent tax credit, and the expense was deductible. He
asked Mr. Gibson to run the figures and report back to the
committee to ensure the legislation is not providing a 30
percent EIC plus 20 percent PPT, plus 25 percent deductibility,
plus a 9.4 percent deduction against the corporate income tax,
and then federal income tax deductions.
5:08:08 PM
MR. GIBSON said he will prepare a stylistic example of how these
credits and deductions would work for a qualified explorer.
5:08:45 PM
REPRESENTATIVE ROSES referred to the 5 percent credit on seismic
surveys and asked if the commissioner is the only person who
would determine whether the acquisition is in the best interest
of the state or whether a procedure is followed prior to the
commissioner's determination.
5:09:04 PM
MS. HOULE said most likely the Resource Evaluation Section group
would review the data and determine whether it is in the state's
best interest to acquire that data. The problem with older
seismic data is that under the current system, an applicant
would request a permit to shoot seismic under the multi-land use
permit from the permits group. The Division of Oil & Gas gets
the confidential data so that data never becomes public. Newer
data becomes public after 10 years under the EIC to make older
data available to companies interested in a specific area.
5:10:16 PM
REPRESENTATIVE ROSES said his concern is that the state would be
giving a 5 percent credit against taxes that would become
managed by a political appointee, not by someone in the best
position to determine what is in the best interest of the state.
A very pro-oil development commissioner is more likely to grant
the five percent credit whenever requested.
5:11:17 PM
MS. HOULE clarified that her group makes the recommendation to
the commissioner based strictly on a technical point of view; it
has no political ambitions.
REPRESENTATIVE ROSES said he just wanted to clarify his
position.
5:11:44 PM
REPRESENTATIVE GUTTENBERG asked how long seismic data remains
confidential.
5:11:55 PM
MS. HOULE explained under the current statutes, seismic data
shot under the multi-land use permit is kept confidential by the
Division of Oil & Gas forever. The division can use the data in
its assessments but it cannot be released to the public. She
noted the data would have to be obtained directly from the owner
but that can be difficult because often several companies are
involved and one may not want the data to be disclosed.
5:12:43 PM
MR. GIBSON continued with his presentation:
[Slide 4] So the first purpose of the EIC language as
we discussed was to broaden the program. The second
objective is to enhance predictability for explorers.
Currently the way the EIC program works under existing
statute, explorers conduct certain ... exploration
activities oftentimes at great expense and then come
back to the state and ask whether or not what they've
done qualifies for a credit under the EIC program.
The intent of the language in the Governor's bill was
to allow additional predictability for explorers so
that by coming in for pre-approval, by coming to the
Department of Natural Resources, for example, and
laying out the exploration plan and allowing it to be
scrutinized by people like the Resource Evaluation
group, the commercial section and others, we could
make a determination as to whether or not it was truly
an exploration program, whether it qualified under the
existing EIC language, and then an explorer could go
more forward with the knowledge that the activity
expenditures that he was undertaking were going to be
eligible for the credit, rather than have this
uncertainty associated with this existing language
that requires them to kind of come hat in hand after
having done their work and ask whether or not the work
they've done qualifies for a credit.
So the intent is to make it more fair, more
predictable for investors on a going forward basis.
5:14:18 PM
MS. HOULE added that would verify the well was being drilled for
a legitimate reason.
5:14:25 PM
CO-CHAIR JOHNSON asked how long it would take to get pre-
approved.
5:14:39 PM
MS. HOULE answered that depends on how cooperative a company is
with the division. Some companies have an ongoing dialog with
the division's geophysicist and engineer and the information
flow is good. In those cases, pre-approval could be granted
within a few weeks to a month, depending on the division's
workload.
5:15:27 PM
CO-CHAIR JOHNSON asked about new entrants that have not
established dialogs.
5:16:08 PM
MS. HOULE noted most new entrants have been pretty forthcoming.
She estimated that given the right data, the division could
probably give them an answer within a few weeks.
5:16:28 PM
MR. GIBSON explained that a tax credit is associated with the
activity undertaken by an explorer. An explorer can undertake
an exploration program absent credits with no delay. An
explorer could proceed under current statute and the point in
time for determining whether the activity is qualified for
credit wouldn't change. This merely makes a shift from a back
end to a front end determination and should have no bearing on
how quickly an explorer can proceed.
5:17:18 PM
CO-CHAIR JOHNSON asked if an explorer filed an application for a
credit a month ago that was approved, what kind of liability the
state would be looking at if the legislature changes rules that
nullify the approval.
5:18:03 PM
MR. GIBSON said he could not put a number on the liability. He
said legislation has frequently changed but only so much
certainty can be provided to industry.
5:18:38 PM
REPRESENTATIVE SEATON questioned whether this program change
requires an applicant to use the pre-approval process to get tax
credits or whether this encourages applicants to explore and
make application later.
5:19:29 PM
MR. GIBSON said his understanding is that this is a wholesale
change to Section (c) of AS 43.55.025, which lays out the
process for filing for and receiving a credit. Under current
statute, that process takes place after expenditure. This new
language repeals and reenacts that section so that the process
would take place on the front end. He believes this change
would no longer allow the post-approval process to take place.
5:20:20 PM
REPRESENTATIVE SEATON questioned whether it is advantageous to
make a total change rather than to allow both processes to be in
place.
5:20:52 PM
MS. HOULE said if the process was an either/or, explorers would
run the risk of not getting their credits.
5:21:02 PM
MR. GIBSON added:
Representative Seaton, I would ... just add to that,
as Julie mentioned, if it was set up so that it was an
either/or situation, for example if an explorer was
uncomfortable with the speed with which the state was
able to conduct its analysis, if there were a
mechanism in place that would allow them to forego
pre-approval and instead opt for approval after the
fact, I'm not sure that that would necessarily be a
major problem but I do think that it's probably
important to make a decision as to whether or not an
explorer should be allowed two bites at the apple.
Either their exploration program is consistent with
the statute and qualifies or it does not.
5:21:53 PM
REPRESENTATIVE GUTTENBERG said he recognizes that legislative
changes could alter the division's relationship with the
industry. He referred to the third bullet on Slide 4, "Prudent
Practice"; and asked if the division has an internal mechanism
in place to determine what that is.
5:22:56 PM
MS. HOULE said the staff in the Resource Evaluation Section have
enough petroleum industry background that they sometimes know
the data better than industry staff and are very capable of
determining what is in the best interest of the state.
5:23:20 PM
REPRESENTATIVE GUTTENBERG asked whether the division ever tells
an applicant to change something because it is wrong.
5:23:37 PM
MS. HOULE said if a company came in with a request to drill
within three miles of an existing well, the division would say
its target objective must be three miles from the existing well,
but division staff would not advise that a prospect is no good.
5:24:29 PM
REPRESENTATIVE GUTTENBERG asked if the division would inform an
applicant of a capped well within 2.5 miles.
5:24:39 PM
MS. HOULE said the division would inform that company.
5:24:54 PM
REPRESENTATIVE GUTTENBERG asked whether the information about
the capped well is subject to confidentiality.
5:24:58 PM
MS. HOULE said if the capped well is public record, the division
could disclose that information. However, even if a well is
drilled within the 24 month confidentiality period, the well's
location would be public knowledge.
5:25:16 PM
CO-CHAIR JOHNSON asked why a company that applied for a permit
to drill within 2.5 miles of another well, and after being
informed of its proximity to another well moved the location a
half mile away, wouldn't then be eligible for the credit. He
also asked why the division wouldn't advise an explorer that it
would be drilling a dry hole if the division had that
information.
5:25:59 PM
MS. HOULE said usually eight of ten wells drilled are dry holes.
5:26:21 PM
CO-CHAIR JOHNSON said she commented that the division would not
tell an applicant if it was applying to drill a well in a bad
location.
5:26:37 PM
REPRESENTATIVE GUTTENBERG asserted, "Sometimes you want to
define the area or you have to drill there, I mean 2.5 miles
instead of 3 miles, you don't think it's there and giving them
the information might determine whether or not they are going to
proceed at all."
5:26:53 PM
MS. HOULE responded that if an explorer was going to drill a
well 2.5 miles within another, it would not qualify for the
credit but the explorer would know that up front.
5:27:09 PM
MR. GIBSON said, in response to Co-Chair Johnson's first
question about allowing a company to come back retroactively,
the division would like companies to make decisions on a
forward-looking basis and deal with applications one time.
While Ms. Houle's staff is extraordinarily talented, it is not a
"deep bench." The division would prefer to agree to a process
and adhere to it.
5:28:25 PM
CO-CHAIR JOHNSON asserted it is refreshing to hear Mr. Gibson
and Ms. Houle say they have adequate staff to do the job.
5:29:02 PM
REPRESENTATIVE SEATON commented:
... I appreciate your clarification of us pre-
approving these as a working interest partner in this
because that clarified it for me that yes, it makes
much sense to do these things upfront instead of
coming at the end because if we're talking about the
30 plus the 20, we are a majority partner in this and
so the idea that somebody might go out and do these
for, you know, tax credits and all, because of some
other tax consequences for other fields that they have
or something, is a possibility. So I do appreciate
that idea and I think I've changed my opinion so your
comments are well taken.
5:30:20 PM
MS. HOULE noted the division needs another reservoir engineer;
currently it has one reservoir engineer who covers the entire
state.
CO-CHAIR JOHNSON asked whether that is a vacant position or new
position.
MS. HOULE clarified the division has a vacant position.
5:30:51 PM
MR. GIBSON continued his presentation:
[Slide 5] We've talked about kind of two of the
intended goals of the language in the Governor's bill,
the first being the - or the second being the
predictability and the other being, kind of enhancing
or expanding the EIC program, but the data sharing
component of this is perhaps the most important. I
think Julie is undoubtedly the most qualified to speak
to this but, again, it comes down to a determination
of whether or not we've struck a reasonable deal with
the existing EIC statutory language. The language is
intended to provide exploration incentive credits to
explorers in exchange for a number of things and among
those things are obviously increased production is
good for the state in terms of royalty and production
tax take but at least as importantly, in terms of
being able to promote or represent what the
prospectivity of various areas is, we've got to have
information. Information is kind of the stock and
trade of Julie's Resource Evaluation group. I think
the best thing to do is to hand it over to the expert
and let her talk to you a little bit.
5:32:22 PM
MS. HOULE told members:
One thing I'd like to reiterate is that this 43.55.025
program is the Department of Revenue's and the
Division of Oil & Gas provides technical guidance to
collect the data and make sure that the state is
getting the data that it needs. As we've been
administering - or helping DOR with the program, we
found a few glitches that we'd like to change in the
program and one of them has to do with seismic data.
Currently there are a couple of aspects that are
troublesome. One is a company can apply for an EIC
now and only the portion over state lands gets credit
so then they only give us the data for that portion
that's on state lands. If you have a checker board
situation where you have private landowners, then we
don't get that data so the problem is you kind of have
an incomplete picture. You have a puzzle with a lot
of pieces missing. Also when you shoot seismic, you
can say well I shot 100 miles and so it was $100,000
so, if I do the math right, I guess $10,000 per mile
but it may not be that each mile is equivalent. You
might have had ... trouble shooting that one line.
You know, it's not really an even split so what we
added in there in the language was that if you apply
for an EIC, you have to provide the entire data set.
5:33:53 PM
REPRESENTATIVE WILSON asked what an EIC is.
5:34:07 PM
MS. HOULE explained an EIC is an exploration incentive credit.
She added another problem that has arisen with seismic data is
that sometimes the seismic shoot is over an existing unit or
outside a unit but it gets sliced at the unit boundary. The
Division of Oil & Gas gets the data, for ten years the only data
released to the public is the data outside of the unit. The
division is thinking ahead about investing in the future when
new explorers want to come in and need a good data set.
5:34:43 PM
MS. HOULE said regarding well data, the division would like to
comport with the AOGCC regulations, which require that well data
be kept confidential for two years. Currently, an explorer can
apply for extended confidentiality if the activity is near
unleased acreage. If an explorer wants a well credit, the
information must be available to the public in two years. The
AOGCC does not collect any fluid or core data. Core data is
collected in Alberta and made available to the public. The
division would like to be able to retain core data and fluid
data for future explorers. She summarized her comments are
intended to sure up some of the glitches in the existing
program.
5:35:59 PM
CO-CHAIR JOHNSON asked if core data means the actual core.
MS. HOULE said that is correct.
CO-CHAIR JOHNSON asked if the actual cores will be stockpiled or
if images of them will be digitized.
5:36:22 PM
MS. HOULE answered that during the two-year confidentiality
period the company could keep the data confidential but would
have to allow the state access to it. After two years, the core
material could be moved to the Geologic Materials Center in
Eagle River.
5:36:53 PM
CO-CHAIR JOHNSON asked whether a fiscal note to build a new
building in which to keep the cores will accompany the bill.
5:37:02 PM
MS. HOULE acknowledged the existing facility needs to be
rebuilt. She noted the core facility in Alberta is supposed to
be world class and there is no reason Alaska cannot have a
similar building.
5:37:24 PM
CO-CHAIR GATTO asked the diameter of the cores.
MS. HOULE said in general, the diameter is 4 inches. The cores
are cut in half lengthwise. Sometimes a two-third, one-third
slab is cut so that one-third can be viewed.
5:37:45 PM
CO-CHAIR GATTO asked if the diameter is 4 inches because when
the core is removed, the hole becomes a well.
5:38:01 PM
MS. HOULE said the size has to do with the ability to get
porosity and permeability data.
5:38:55 PM
REPRESENTATIVE GUTTENBERG questioned whether she is talking
about exploratory wells and not wells that go into production.
MS. HOULE answered the current AOGCC regulations are being
changed so that development well data immediately becomes public
one month after it is drilled. She said she was referring to
exploration wells that fall under the two-year confidentiality
period.
5:39:17 PM
REPRESENTATIVE ROSES asked when the two-year time clock starts
ticking.
5:39:30 PM
MS. HOULE replied it begins when they finish drilling the well.
5:39:45 PM
REPRESENTATIVE WILSON noted that in previous testimony, oil
company representatives expressed concerned about providing
certain data. She asked if that concern was directed at the
data requested by the Department of Revenue or whether it also
applies to the data to which Ms. Houle is speaking.
5:40:19 PM
MS. HOULE said that is a good point and that one company is
particularly concerned about having to provide core data. She
believes the division can assure confidentiality. She pointed
out that is common practice in Alberta and other countries.
5:40:52 PM
MR. GIBSON reiterated the state is paying for this information
so it is appropriate to ask for certain data.
5:41:05 PM
MS. HOULE added the state is giving a credit and investing in
explorers today and will be making data available later on to
new explorers that will have new technology.
5:41:26 PM
MR. GIBSON told committee members their presentation was
concluded.
5:41:41 PM
CO-CHAIR GATTO announced that all of the documents that have
been presented to the House Resources Committee are available
online at: House Majority.org, under a caption entitled "What's
Inside," under House Resources Committee/ACES/PPT.
[HB 2001 was held over.]
5:42:30 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 5:43:15
PM.
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