02/13/2013 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB72 | |
| HB4 | |
| HB72 | |
| Adjourn |
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 72 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| += | HB 4 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
February 13, 2013
1:03 p.m.
MEMBERS PRESENT
Representative Eric Feige, Co-Chair
Representative Dan Saddler, Co-Chair
Representative Peggy Wilson, Vice Chair
Representative Mike Hawker
Representative Craig Johnson
Representative Kurt Olson
Representative Paul Seaton
Representative Geran Tarr
Representative Chris Tuck
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Representative Mike Chenault
COMMITTEE CALENDAR
HOUSE BILL NO. 72
"An Act relating to appropriations from taxes paid under the
Alaska Net Income Tax Act; relating to the oil and gas
production tax rate; relating to gas used in the state; relating
to monthly installment payments of the oil and gas production
tax; relating to oil and gas production tax credits for certain
losses and expenditures; relating to oil and gas production tax
credit certificates; relating to nontransferable tax credits
based on production; relating to the oil and gas tax credit
fund; relating to annual statements by producers and explorers;
relating to the determination of annual oil and gas production
tax values including adjustments based on a percentage of gross
value at the point of production from certain leases or
properties; making conforming amendments; and providing for an
effective date."
- HEARD & HELD
HOUSE BILL NO. 4
"An Act relating to the Alaska Gasline Development Corporation;
making the Alaska Gasline Development Corporation, a subsidiary
of the Alaska Housing Finance Corporation, an independent public
corporation of the state; establishing and relating to the in-
state natural gas pipeline fund; making certain information
provided to or by the Alaska Gasline Development Corporation
exempt from inspection as a public record; relating to the Joint
In-State Gasline Development Team; relating to the Alaska
Housing Finance Corporation; relating to judicial review of a
right-of-way lease or an action or decision related to the
development or construction of an oil or gas pipeline on state
land; relating to the lease of a right-of-way for a gas pipeline
transportation corridor, including a corridor for a natural gas
pipeline that is a contract carrier; relating to the
Corporation; relating to the review by the Regulatory Commission
of Alaska of natural gas transportation contracts; relating to
the regulation by the Regulatory Commission of Alaska of an in-
state natural gas pipeline project developed by the Alaska
Gasline Development Corporation; relating to the regulation by
the Regulatory Commission of Alaska of an in-state natural gas
pipeline that provides transportation by contract carriage;
relating to the Alaska Natural Gas Development Authority;
relating to the procurement of certain services by the Alaska
Natural Gas Development Authority; exempting property of a
project developed by the Alaska Gasline Development Corporation
from property taxes before the commencement of commercial
operations; and providing for an effective date."
- HEARD & HELD
PREVIOUS COMMITTEE ACTION
BILL: HB 72
SHORT TITLE: OIL AND GAS PRODUCTION TAX
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
01/16/13 (H) READ THE FIRST TIME - REFERRALS
01/16/13 (H) RES, FIN
02/11/13 (H) RES AT 1:00 PM BARNES 124
02/11/13 (H) Heard & Held
02/11/13 (H) MINUTE(RES)
02/13/13 (H) RES AT 1:00 PM BARNES 124
BILL: HB 4
SHORT TITLE: IN-STATE GASLINE DEVELOPMENT CORP
SPONSOR(s): HAWKER, CHENAULT
01/16/13 (H) PREFILE RELEASED 1/7/13
01/16/13 (H) READ THE FIRST TIME - REFERRALS
01/16/13 (H) RES, FIN
01/30/13 (H) SPONSOR SUBSTITUTE INTRODUCED
01/30/13 (H) READ THE FIRST TIME - REFERRALS
01/30/13 (H) RES, FIN
02/04/13 (H) RES AT 1:00 PM BARNES 124
02/04/13 (H) Heard & Held
02/04/13 (H) MINUTE(RES)
02/06/13 (H) RES AT 1:00 PM BARNES 124
02/06/13 (H) Heard & Held
02/06/13 (H) MINUTE(RES)
02/13/13 (H) RES AT 1:00 PM BARNES 124
WITNESS REGISTER
MICHAEL PAWLOWSKI, Oil & Gas Development Project Manager
Office of the Commissioner
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: Provided a PowerPoint overview of HB 72 and
answered questions related to the bill.
JOE BALASH, Deputy Commissioner
Office of the Commissioner
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Discussed the proposed gross revenue
exclusion (GRE) provision in HB 72.
BARRY PULLIAM, Economist & Managing Director
Econ One Research, Inc.
Los Angeles, California
POSITION STATEMENT: As consultant to the administration,
provided a PowerPoint presentation entitled, "Analysis of
Alaska's Tax System, North Slope Investment and the
Administration's Proposal, HB 72".
RENA DELBRIDGE, Staff
Representative Mike Hawker
Alaska State Legislature
Juneau, Alaska
POSITION STATEMENT: On behalf of Representatives Mike Chenault
and Mike Hawker, joint prime sponsors of SSHB 4, continued
review of the sectional analysis.
TINA GROVIER, Attorney, Natural Resources and Energy Law
Birch Horton Bittner & Cherot
Counsel to Alaska Gasline Development Corporation (AGDC)
Anchorage, Alaska
POSITION STATEMENT: Answered questions related to SSHB 4.
DARYL KLEPPIN, Manager
Commercial Team
Alaska Gasline Development Corporation (AGDC)
Alaska Housing Finance Corporation (AHFC)
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: Answered questions related to SSHB 4.
FRANK RICHARDS, Manager
Pipeline Engineering & Government Affairs
Alaska Gasline Development Corporate (AGDC)
Alaska Housing Finance Corporation (AHFC)
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: Answered questions related to SSHB 4.
ACTION NARRATIVE
1:03:47 PM
CO-CHAIR ERIC FEIGE called the House Resources Standing
Committee meeting to order at 1:03 p.m. Representatives Tuck,
Tarr, Seaton, Olson, Hawker, P. Wilson, Saddler, and Feige were
present at the call to order. Representative Johnson arrived as
the meeting was in progress.
HB 72-OIL AND GAS PRODUCTION TAX
1:04:06 PM
CO-CHAIR FEIGE announced that the first order of business is
HOUSE BILL NO. 72, "An Act relating to appropriations from taxes
paid under the Alaska Net Income Tax Act; relating to the oil
and gas production tax rate; relating to gas used in the state;
relating to monthly installment payments of the oil and gas
production tax; relating to oil and gas production tax credits
for certain losses and expenditures; relating to oil and gas
production tax credit certificates; relating to nontransferable
tax credits based on production; relating to the oil and gas tax
credit fund; relating to annual statements by producers and
explorers; relating to the determination of annual oil and gas
production tax values including adjustments based on a
percentage of gross value at the point of production from
certain leases or properties; making conforming amendments; and
providing for an effective date."
Co-Chair Feige noted today would be a continuation of the
administration's presentation from February 11, 2013.
1:04:22 PM
MICHAEL PAWLOWSKI, Oil & Gas Development Project Manager, Office
of the Commissioner, Department of Revenue (DOR), noted he is
the advisor for petroleum fiscal systems to the Department of
Revenue. He reminded members that during the committee's last
meeting he provided a PowerPoint review of the broad provisions
of HB 72 and where those are located within the bill, the
elimination of progressivity, the elimination of the North Slope
qualified capital expenditure (QCE) credits, and the North Slope
net operating loss credits. Continuing that presentation with
slide 5, he turned to the provision for small producer tax
credits contained in Section 16 of the bill, page 16, line 26.
The small producer tax credit is in current statute, he said,
and is a credit consistent with the treatment of other credits
in the North Slope in the governor's proposal in that it is a
nontransferable credit that may only be taken against production
taxes. The current small producer tax credit is set to expire
in 2016 for new production, which means new production under the
current law would have to come into production before 2016 to
qualify for the credit. Page 16, line 29, proposes to change
the date to 2022. Thus, HB 72 would maintain the current small
producer tax credit, but allows production to come on line up to
2022 to qualify for the purposes of the credit.
1:06:19 PM
REPRESENTATIVE SEATON inquired whether there is any interaction
between the small producer tax credit extension and the changing
of when the credits can be applied for and received.
MR. PAWLOWSKI replied the interaction between the two credits
will be discussed later by Mr. Pulliam [of Econ One Research,
Inc.] when he reviews the lifecycle economics of projects. The
small producer credit is for the first nine years of production.
The carry forward credit is for 10 years. They are similar in
length, but there is not a direct nexus between the two.
1:07:19 PM
REPRESENTATIVE SEATON said he is interested not only in the
aforementioned, but also what classifies as new oil. He asked
whether there is a different definition of new oil that would
qualify for the small producer tax credit than the current
definition. He further asked whether there is a change in that
interaction that changes the applicability of the small producer
tax credit; for example, would some of the current new oil
production that qualifies for small producer tax credit be
eliminated by restrictions on where the oil comes from.
MR. PAWLOWSKI responded a deeper conversation may be needed
about the nuances of the relationship between the specific
projects being talked about by Representative Seaton. He said
the small producer credit is for any producer that did not have
commercial oil or gas production from a lease or property in the
state before April 1, 2006. So, that is new production coming
on line for purposes of this small producer credit. The
provisions in the governor's bill that relate to new oil are
specifically the gross revenue exclusion, which Deputy
Commissioner Balash will speak to later. A producer would
certainly qualify for a small producer tax credit and the gross
revenue exclusion depending on where that production came from.
So, stepping forward, it would have to be a new participating
area or unit formed after 2003 to qualify. There is no taking
away of the credit, it is just extending the qualification
period.
REPRESENTATIVE SEATON requested a flowchart that explains how
the different credits interact to show whether one aspect of the
bill impacts another.
1:09:49 PM
MR. PAWLOWSKI, returning to his sectional analysis, stated that
Section 24 is the main section of the bill for the gross revenue
exclusion (GRE) provision [slide 6]. He turned over discussion
of this section to Deputy Commissioner Joe Balash.
1:10:09 PM
JOE BALASH, Deputy Commissioner, Office of the Commissioner,
Department of Natural Resources (DNR), explained that Section
24, page 23, lines 1-10, is the primary incentive being provided
in HB 72 for the production of new oil. From the debate over
the past couple years, he said he thinks there is a consensus on
a willingness to provide reduced taxes and a tax relief for the
production of new barrels. The mechanism employed in HB 72 is
through the gross revenue exclusion, which starts at the gross
value at the point of production. The GRE reduces that value
before applying the costs in the determination of production tax
value against which the tax rate is applied. It basically has
the effect of reducing the tax rate. There are two ways to
qualify for the GRE on the barrels a taxpayer is producing. The
first is if those barrels are being produced from a unit that
was formed after January 1, 2003, and the second is if those
barrels are being produced from a participating area (PA) that
was approved by DNR after January 1, 2012. During calendar year
2012 there were no new PAs approved, so there is not anything
that falls in between, it would be anything that is approved
prospectively. The language is clear that a taxpayer can
qualify one way or the other, but cannot double dip, cannot
qualify for two reductions.
1:12:12 PM
MR. BALASH defined a participating area, explaining that when
DNR issues a lease, an oil or gas deposit found during
exploration of the lease area does not confine itself to a
single lease. It is generally present through multiple leases
and the leases then are put together in a block called a unit.
Leases in units are measured in two dimensions as just an
outline on a map. A participating area measures that property
in a third dimension with depth. For the property to be part of
the PA, it must be contributing to production in the field, it
must be contributing to oil or gas in the wellbore. Tried and
true methodological practices are used by the geologists and the
petroleum reservoir engineers to understand and agree on what is
in and what is not. A certain amount of tension exists between
the various owners inside the field because each owner wants to
ensure that its barrels, its property, is getting counted if it
is producing; the owner on the other side of the table wants to
ensure that the other owner is not getting an extra benefit by
counting barrels that the other owner is not actually producing.
Within those columns of earth are pockets of oil and gas that
are being tapped by the various wellbores. Any pool or separate
reservoir that is not penetrated by a well, and not contributing
to production, is not part of a PA. Companies can come back
later to apply for a new PA that is separate and distinct from
the existing production, and that is what is being talked about
here - a method to allow the GRE to apply to new oil inside the
legacy fields, but not part of the same legacy reservoir.
1:14:34 PM
REPRESENTATIVE SEATON recounted his tour of the North Slope this
past year with ConocoPhillips Alaska, Inc. where he saw a
working oil tube rig that was re-drilling existing wellbores and
putting out eight spiders in different directions to get to
places where there was not good continuity because of fault
blocks and such, but it was the same sands, the same area. He
asked whether the ends of each of those eight spiders would now
be considered new participating areas.
MR. BALASH said the answer would be no if it is for drilling
into the same reservoir and extending by using sophisticated
drilling techniques that were not possible 25 years ago. That
would be an expansion or extension of a PA because DNR's
management system for PAs tries to keep like rocks in the same
system in the same PA. Under the bill's current language, an
expanded PA would not qualify; it must be a new PA. That is not
to say there could not be a conversation about that kind of a
mechanism. Using the horizons at Prudhoe Bay to provide an
example, he explained that the initial production area in the
Sadlerochit Reservoir is where the most prolific rocks are in
reservoir and production comes from. However, there are other
horizons that are separate and distinct reservoirs within the
Prudhoe Bay Unit and over time there have been multiple PAs
formed within the Prudhoe Bay Unit. It is those new areas
within that third dimension of the unit that are being talking
about. Prudhoe Bay has been pretty heavily developed and
produced, but an example of something that likely would qualify
at some point would be the Ugnu Sands. Ugnu has not contributed
to production to date in Prudhoe Bay, so a new participating
area could be formed for the Ugnu layer at Prudhoe Bay.
1:17:59 PM
REPRESENTATIVE SEATON understood BP was producing about 6,000
barrels a day of heavy/viscous oil from sands as a test pilot
[in the Milne Point Unit]. He asked whether that area would be
considered to have contributed production and therefore would
not qualify for the reduced tax rate of 20 percent.
MR. BALASH answered he will double check that specific case with
his staff, but offered his understanding that it is sustained
commercial production of oil and gas that is being talked about.
He said he does not know off the top of his head whether what
was being tested at Milne is currently in, or was in, a PA. He
suggested having Director Barron provide a presentation on how
DNR utilizes PAs within the units to manage the resource.
Director Barron's presentation has an animated illustration that
shows the different horizons and the different pools that are
not the same reservoir in those horizons.
1:19:45 PM
REPRESENTATIVE SEATON posited he can see a big incentive for
shutting down parts of the field for a while so there is no
longer sustained production and then coming back so as to reduce
the tax rate by 5-7 percent. He therefore requested that when
DNR comes back with a presentation he would like to hear from
"legal" as to what sustained production is and where it does and
does not apply.
MR. PAWLOWSKI directed attention to page 23, lines 8-9, which
state, "the participating area does not contain a reservoir that
had previously been in a participating area ...." So, he said,
if it had sustained production at one point and was shut down,
it would have been in a participating area. That language was
put in place to specifically prohibit the aforementioned type of
scenario. He stated he will work with "legal" to get the
requested analysis for the committee.
1:21:27 PM
MR. PAWLOWSKI resumed his sectional analysis, noting the vast
majority of the bill is related to [Cook Inlet and Middle Earth]
[slide 7]. Over the years, different tax ceilings and different
tax treatments have been put into place for gas produced and
used in-state, oil produced from the Cook Inlet, gas produced
from the Cook Inlet, and gas produced from Middle Earth, which
is the area not on the North Slope and not in Cook Inlet.
Because the legislature's work on those specific, distinct
policy calls must be preserved, much of the language in HB 72 is
conforming language to account for those different tax ceilings
and the way the language moves around when progressivity is
repealed throughout the tax treatment.
1:22:23 PM
MR. PAWLOWSKI said the main change is on page 2, lines 19-24
[Section 3] and that this presented a bit of a conundrum for the
departments in putting the bill together. Subsection (o) of the
production tax [AS 43.55.011] is where preference is given to
gas produced in-state and used in-state. Senate Bill 23, passed
[in 2012], included a separate ceiling of 4 percent gross for
gas and oil produced from the Middle Earth. That separate tax
treatment did not distinguish between gas or oil produced from
that area, so the Department of Law and the administration went
with the most recent treatment of that specific type of gas with
the understanding that during that process operators had
expressed concerned about having to do too much separate
accounting between the oil and gas that were coming out of the
same wellbore. The thought was that it was simpler to have the
provisions that were passed in Senate Bill 23, which is AS
43.55.011(p) and which is the new language seen on page 2, line
23. This clearly says that gas produced and used in-state is
subject to the existing ceiling, unless the gas comes from
Middle Earth and then it is subject to the Middle Earth
provisions that were passed last year. The relationship was
never dealt with in the statute when Senate Bill 23 passed.
Thus, this is the one place where there is a difference between
the treatment of existing statute and recent statute.
Everywhere else is a conforming section. For example,
conforming Section 4, page 3, line 4, is the clarification
language, "not subject to AS 43.55.011(o) or (p)" which gets
back to the different tax treatments and preserving them.
1:24:42 PM
MR. PAWLOWSKI moved to conforming Section 13, page 12, line 18.
He reminded members that [Section 11] changes the word
"certificates" to "certificate" because the bill provides that
the [qualified capital expenditure] credit will be issued in a
single certificate [whether for north of the North Slope or for
south of the North Slope]. Continuing, he stated that "there
was already a statute, AS 43.55.023(m), which said contrary to
the statute that says that you have to take a credit and divide
it into two certificates, if the credit is earned south of the
North Slope it can be taken as one certificate." The bill
repeals AS 43.55.023(m), so page 12, line 20, states "of this
section or former (m)" in recognition that (m) is being
repealed. These conforming sections make it clear the existing
credits that are retained can be taken as one certificate.
1:26:20 PM
REPRESENTATIVE P. WILSON referred to page 2 and said it is hard
to visualize because "in the bill ..., after this is all done,
there is going to be a (p) even though in here there is not a
(p)".
MR. PAWLOWSKI replied that AS 43.55.011(p) was the provision in
Senate Bill 23 that passed in the last legislature and
incorporating that provision throughout the statute is what is
going on here.
1:27:19 PM
MR. PAWLOWSKI, proceeding with his sectional analysis, stated
these conforming sections continue throughout HB 72. For
example, Section 17, page 17, lines 3-21, references that at one
point AS 43.55.023(m) existed. In that there was a credit
issued under AS 43.55.023(m) that a company waited several years
to bring back to the state, there needs to be a reference in
statute that at one point a section did exist that allowed that
credit to be issued as a single certificate rather than two
certificates.
1:28:12 PM
REPRESENTATIVE SEATON noted that HB 72 pushes to limit capital
credits so during low prices the state is not obligated to take
money out of its savings to pay for credits. However, during
times of low prices and a poor economy, would this requirement
for taking the credits in one year instead of two be opposite
the philosophy to limit the state's liability, he asked.
MR. PAWLOWSKI explained those sections preserve the existing
treatment of tax credits south of 68 degrees [North latitude],
meaning not the North Slope. It is for activity in Cook Inlet
and Middle Earth, which under current law are already allowed to
be taken in one year. In further response to Representative
Seaton, Mr. Pawlowski explained that the credit for the North
Slope that had to be divided into two years was the qualified
capital expenditure credit and that credit is being eliminated.
1:30:09 PM
REPRESENTATIVE SEATON drew attention to Section 23, page 22,
lines 12-31, and inquired whether the gross revenue exclusion
(GRE), which effectively lowers the tax rate from 25 percent to
18 percent, has a sunset or will new oil be treated at 18
percent forever.
MR. PAWLOWSKI cautioned against picking specific numbers because
each tax rate will functionally depend on the actual capital
costs of that specific project because it is still in that
system. The provision is saying that future development will
get a benefit of 20 percent of the gross value of that future
production. There is no sunset for two reasons. First, in
looking at the lifecycle economics of these more challenged,
higher cost projects, there needs to be that help to the
economics and the government take. Second, in looking at
previous efforts that stopped or time limited that benefit, it
was seen that it takes time to drill out a prospect; all of the
wells for a prospect are not drilled in one year. From the
start of sustained production, it takes 10-15 years to truly
drill out the prospect, so it becomes functionally the same over
time anyway. The concern with a timeline was that a company
would be unable to realize the benefit that the gross revenue
exclusion is actually trying to put on the table.
1:32:23 PM
REPRESENTATIVE SEATON stated that if the tax rate is going to
functionally be changed permanently from 25 percent to more or
less 18 percent, depending upon the capitalization of a project,
he would like to see the effect on the point in the future at
which 50 percent of the oil is considered new oil. Because this
is for new oil and the state is counting on new oil, the bill as
structured would, over time, drastically reduce the tax if there
is no sunset date.
MR. PAWLOWSKI answered that DOR will work on that and bring it
back for presentation to the committee, but explained that it
gets back to the nexus of that participating area approach.
1:34:07 PM
BARRY PULLIAM, Economist & Managing Director, Econ One Research,
Inc., began his presentation regarding Alaska's tax system,
North Slope investment and the administration's proposal, HB 72.
He noted he has been working for and with the administration,
the Department of Revenue, and the Department of Natural
Resources on this tax issue to help analyze what has been
occurring on the North Slope, to look at Alaska's tax system
relative to other areas, to look at what has happened with
respect to investment in production in Alaska, and to think
about appropriate changes to that system. He said he will be
discussing the work that has been done over the last several
months and how the changes proposed in HB 72 will affect the
activity going on in Alaska.
MR. PULLIAM stated Econ One provides economic research to a
variety of industries, with the energy industry being the area
he works in [slide 2]. It has worked for and with the State of
Alaska for about two decades on a variety issues, and has worked
for the administration as well as for the legislature. He said
he spent a lot of time in Alaska in 2006 and 2007 when the
legislature was considering the production profits tax (PPT),
Alaska's Clear and Equitable Share (ACES), and gas line issue.
In addition to Alaska, Econ One works for several oil producing
states, the federal government, and energy companies.
1:36:48 PM
MR. PULLIAM first provided some background on the North Slope
[slide 4], stating that to date the North Slope has produced
about 16 billion barrels of oil. Approximately 5.5 billion
barrels of economically recoverable oil are believed left in
currently known fields. The vast majority of oil produced from
the North Slope has come from the giant fields of Prudhoe Bay
and Kuparuk [River]. About 90 percent of the resources
discovered to date were discovered prior to 1970.
1:38:11 PM
MR. PULLIAM explained that slide 5 puts the historical
production in context with what is believed to still exist on
the North Slope. Estimates are that the North Slope contains
about 40 billion barrels of additional economically recoverable
resources at today's prices and about 5.5 billion barrels sits
in fields that have already been discovered. Another 19 billion
barrels sits in fields that are yet to be discovered on state
and federal lands, according to the U.S. Geological Survey
(USGS). Responding to Co-Chair Feige, Mr. Pulliam said he is
talking about both onshore and offshore.
1:39:18 PM
MR. PULLIAM, in response to Representative Tuck, stated that the
red portion of the pie chart on slide 5 depicts the amount of
oil produced to date, and the red and green portions together
represent [the total discovered resources] to date depicted on
slide 4. Responding further, he confirmed that the purpose of
HB 72 is to incentivize [production] from the [discovered
conventional resources estimated at 5.5 billion barrels of oil].
The bill would also incentivize part of the [undiscovered
conventional resources estimated at 19.2 billion barrels] and
potentially the the unconventional resources [estimated at 5.5
billion barrels]. The aforementioned is everything that has not
been produced to date that Alaska's tax system covers. He
further confirmed that unconventional resources means shale and
heavy and viscous oil, which is not the light, conventional oil
that has been produced to date.
1:40:47 PM
REPRESENTATIVE SEATON understood that in the pie chart on slide
5, the [undiscovered conventional resources], the [Arctic
National Wildlife Refuge (ANWR)], and the [unconventional
resources] would all be subject to the gross revenue exclusion.
MR. PULLIAM answered that part of the [undiscovered conventional
resources] is federal or offshore production that the state does
not tax and which would not be subject to HB 72. The portion
that is on state property would be subject to HB 72.
REPRESENTATIVE SEATON requested that at some future date this be
delineated for the committee.
MR. PULLIAM replied that the next slide shows a breakdown that
will be helpful in this regard.
1:42:10 PM
REPRESENTATIVE TUCK referenced a report handed out to the
committee on 2/11/13 that demonstrated the current natural
decline of the major fields of Prudhoe Bay and Kuparuk. He
inquired whether this natural decline can be prevented.
MR. PULLIAM responded it is ultimately unpreventable because the
amount of oil there is fixed, although the exact extent of that
oil is unknown. Finding new resources within the field itself
is something that can be done and it can be done to slow the
decline rate or it can be done to also increase the production.
But that is going to require getting at pockets of oil within
those fields that have not currently been gotten to. Some of
that decline has to do with the way those fields are constructed
and the facilities that are there. There is a certain amount of
gas handling capacity, particularly at Prudhoe Bay, that limits
what can be produced over time. As oil is produced, the ratio
of gas to oil increases, which is a natural occurrence, and with
that fixed capacity in place there is some limitation there.
But if that capacity is changed, more oil can be produced. If
the capacity to handle gas was doubled, then a lot more oil
could be produced.
1:44:21 PM
REPRESENTATIVE TUCK surmised the aforementioned would affect the
[discovered conventional resources] and [historical production]
sections depicted in the pie chart on page 5.
MR. PULLIAM answered it would affect the [discovered
conventional resources] but not the [historical production].
The [discovered conventional resources] is an estimate based on
the technology known today. It is important to keep in mind, he
continued, that these fields have produced much more oil than
had been thought possible; technology has done wonders and
prices have played a part as well. As technology gets better
these portions of the pie will grow, particularly for the
estimated 5.6 billion barrels of oil for discovered conventional
resources.
1:45:36 PM
MR. PULLIAM resumed his presentation, discussing the locations
of undiscovered conventional oil resources [on the North Slope,
slide 6]. According to the U.S. Geological Survey (USGS), he
reported, at $90 per barrel there are about 3 billion barrels of
economically recoverable oil on onshore state lands, 5.8 billion
barrels in the Beaufort Sea, almost 10 billion in the Chukchi
Sea, about 0.5 billion in the National Petroleum Reserve-Alaska
(NPR-A), and close to 10 billion in the Arctic National Wildlife
Refuge (ANWR), for a total of about 29 billion barrels. He
noted that $90 per barrel is a little less than the price of
today. He said the size of these fields is likely to be in the
range of 50 million barrels, which is a lot smaller than the
typical field producing on the North Slope today, but in line
with the more recent discoveries that Alaska has had.
Responding to Co-Chair Feige, he explained that the columns on
slide 6 for "P95" and "P5" indicate probabilities. If all the
oil was found, P5 means a 5 percent probability that there would
be more than that amount of oil, and P95 means a 95 percent
chance that there is more than that volume. For example, the
estimate for the Central North Slope is that there is a 95
percent chance of at least 2.8 billion barrels left and only a 5
percent chance of more than 3.9 billion barrels left; however,
the mean in that range is about 3.4 billion barrels, which is a
pretty tight range.
1:47:55 PM
REPRESENTATIVE TARR referred to slide 6 and inquired whether the
figures in the economically recoverable column are under HB 72
or under ACES.
MR. PULLIAM replied he thinks this analysis was done under the
current law of ACES.
1:48:21 PM
MR. PULLIAM, returning to his presentation, summarized the
unconventional oil resources [on Alaska's North Slope, slide 7].
Not much is yet known about shale, he said. A [2012] USGS
report put the mean technically recoverable barrels at about 1
billion. It has not been shown to be economic and that estimate
is very preliminary. He noted that the early estimates by the
USGS of recoverable shale oil in the Lower 48 were much lower
than what they have turned out to be and what is being thought
now. Regarding viscous and heavy oil, he said it is known there
is a lot of that oil in place, somewhere in the range of 25
billion barrels, but the current estimate is that only 15
percent, 4-6 billion barrels, is economically recoverable. He
reiterated that, historically, technology advances and allows
getting more of that original oil out than was once thought, so
it would not be surprising to see that number increase.
1:49:54 PM
REPRESENTATIVE TARR observed that the estimated 5.5 billion
barrels of unconventional oil resources depicted on slide 5 is
less than what is depicted on slide 7.
MR. PULLIAM responded slide 5 depicts the mid-point of heavy
oil, which is 3.6-5.6, plus the 1 billion for shale.
1:50:27 PM
MR. PULLIAM, resuming his presentation, provided a history of
Alaska's production tax system on the North Slope [slide 8]. He
said the state began with a gross system when oil first started
flowing in 1977 at a maximum tax rate of 12.25 percent, which
was the highest rate in the country at the time. The economic
limit factor (ELF) was also introduced at that time. In 1981
the maximum rate was increased to 15 percent, which was again
the highest rate in the country. New fields were given a 12.25
percent rate for the first 5 years of production. Modifications
to ELF occurred in the late 1980s. Not much happened between
then and 2003, at which time exploration credits [of 20-40
percent] were introduced. In 2005 the Prudhoe Bay fields were
aggregated for purposes of calculating ELF, which raised the
effective tax rate on the satellites around Prudhoe Bay. In
2006, the petroleum profits tax (PPT) was introduced. The PPT,
[a net-based tax system], was a fundamental shift from the gross
system, which many at the time recognized had some real flaws,
one being the operation of ELF and how it reduced the tax rate
in areas where it was not really necessary. The other flaw was
that the gross system did not always align the economics of the
producers with the economics of the state and was thought to be
inhibiting production, particularly high cost production.
1:52:34 PM
MR. PULLIAM, continuing the history of Alaska's production tax
system, said the PPT, being a net-based tax system, allowed the
deduction of operating and capital costs. The PPT legislation
as originally introduced had a 20 percent base rate with a 20
percent credit. During the course of the 2006 sessions, that
was ultimately changed to a 22.5 percent base rate with a 0.25
percent progressivity piece that kicked in when the net taxable
value was $40 per barrel, for a maximum combined rate of 47.5
percent. In 2007, PPT was amended to the current system under
Alaska's Clear and Equitable Share (ACES). Key differences
between ACES and PPT were that the base rate was changed to 25
percent, the progressivity was increased to 0.4 percent and the
trigger point was dropped to $30. At over $92.50 net, the
progressivity flattens out to a 0.1 percent increase and the
maximum rate was increased to 75 percent, which is not reached
until very high prices. However, he pointed out, the 75 percent
number gets published and people associate that number with
Alaska.
1:54:14 PM
MR. PULLIAM moved to discussing the benchmarking done for Alaska
North Slope (ANS) activity and how it has behaved over the past
decade compared to other areas [slide 10]. To control for
price, technology, and general economic conditions that impact
activity, the North Slope activity was benchmarked against other
producing areas in countries belonging to the Organisation for
Economic Co-operation and Development (OECD). Since no two areas
are exactly alike, benchmarking looks at places that have as
much in common as possible to allow for the most meaningful
comparisons. Areas used for benchmarking the North Slope
include the North Sea, the rest of the U.S. and some key
producing states, Canada, and Australia. These areas are
comparable to Alaska in that they have similar political and
legal structure and they all have significant prospectivity,
meaning there is a lot of oil left to find. However, the easy
oil has been produced in all of these areas and what remains is
largely high cost conventional and unconventional oil. Also
common to these areas is that their resources are developed for
the most part by the private sector, so the people looking for
and producing oil all respond to similar types of incentives.
1:56:40 PM
MR. PULLIAM said the aspects looked at for the benchmarking were
crude [oil] production, capital spending, [petroleum sector]
employment, and drilling activity [slide 11]. Production on the
Alaska North Slope has declined to just over 40 percent of what
it was a decade ago. Capital spending on the North Slope
increased in the mid-2000s and has remained fairly level for the
last 4-5 years. Employment in the North Slope petroleum sector
increased in about 2006, partly in response to corrosion events
and then the efforts to rebuild and renew much of the North
Slope facilities, particularly in the legacy fields. Drilling
activity has declined as production has gone down.
1:58:19 PM
REPRESENTATIVE TARR inquired whether the 2006 increase in
petroleum sector employment could have been related to either of
the two changes in the tax system.
MR. PULLIAM answered the activity on the North Slope has been
largely related to facility renewal, and some of that may be
driven and aided by ACES. The increase in employment has not
seen a corresponding increase in drilling. There is a very real
need to update many of those old facilities on the North Slope
and ACES has been helpful, and the state has provided a lot of
the funding for doing that.
1:59:46 PM
REPRESENTATIVE SEATON, in regard to benchmarking against OECD
countries, asked why not benchmark against areas where industry
is investing, such as Russia, because where industry is putting
its capital would tell what is important to them.
MR. PULLIAM replied it will be seen in coming slides that
industry is putting a significant amount of capital into all of
these OECD areas that the benchmarking is looking at. Regarding
Russia, a nice thing about the OECD areas is that a lot of
trustworthy data is available; outside of that it is harder to
find the same type and quality of information to do those
comparisons. For all of the reasons summarized on [slide 10],
such as similarity of legal and political systems, the OECD
areas looked at do provide a good benchmark without having to go
outside of those areas, such as to Russia.
2:01:34 PM
MR. PULLIAM continued his presentation, summarizing the four
activities for the benchmark areas [slides 12-15]. He noted
that the appendix provides these same comparisons in detail. He
said the North Sea (slide 12) is a good comparison to Alaska
because the two are alike in many ways. The North Sea was
discovered and developed about the same time [as the North
Slope]. North Sea production has historically come from large
fields and then smaller discoveries in and around those large
fields. The North Sea has experienced the same kind of decline
as has Alaska, being a mature basin in many areas, but yet with
lots of oil still in the ground. The North Sea had the same
pattern in capital spending as Alaska until the last few years
when capital spending increased in the North Sea. Drilling in
the North Sea declined then stabilized in the last few years.
2:03:32 PM
CO-CHAIR SADDLER returned to the history of Alaska's production
tax system on slide 8 and asked what the overall effective tax
rates were for ELF, ELF II, and PPT so the committee can have a
basis for comparison of the take over those years.
MR. PULLIAM responded it changed over time and was different for
each field, but said for 2005 he recalls an average tax rate of
about 10 percent; with the rate being higher at Prudhoe Bay,
lower at Kuparuk River Unit, and lower at the other fields. In
further response, he confirmed that was on a gross basis and
that today Alaska would be at a 20 percent or more tax rate on a
gross basis. He agreed to calculate the gross tax rate for the
decades between 1977 and 2007 and provide that information to
the committee.
2:05:01 PM
REPRESENTATIVE TUCK said it appears from research he has done
that the North Sea is naturally declining like Alaska. He
related that according to a recent news story in London's
Guardian, the North Sea's oil and gas reserves are running out
fast. Since comparisons of capital spending and drilling for
the North Sea and Alaska are good ones, he inquired whether the
North Sea has reduced or reversed its production decline.
MR. PULLIAM answered the United Kingdom (UK) has targeted
several programs, one being the Brownfield Allowance, which is a
reduction in the tax rate for approved development spending that
is designed to get additional barrels out of existing fields.
This would be like the Gross Revenue Exclusion (GRE). The
allowance significantly impacts the economics for producers and
there has been a lot of response from that.
2:07:03 PM
MR. PULLIAM returned to his presentation and reviewed the four
areas for the U.S. excluding Alaska North Slope [slide 13].
Crude oil production has increased in the U.S., as opposed to
Alaska's decline. Capital spending has increased in the U.S.
Moving to slide 14, he said an increase in production has also
occurred in Canada, much of that being from heavy oil in
Alberta, an example of technology and prices coming together to
allow this increased production. Turning to slide 15, he noted
that in Australia much of the activity in recent years has gone
from mostly producing oil to developing liquefied natural gas
(LNG) from that country's significant gas resources. He offered
to walk through the details of these comparisons that are in the
appendix with any committee member wishing to do so.
2:08:27 PM
MR. PULLIAM next provided a side-by-side comparison of crude oil
production between the Alaska North Slope, the rest of the U.S.,
and OECD countries [slide 16]. He said he indexed the values
depicted on the graph to the 2003 level so as to put the
comparisons on a comparable basis. In 2003, the North Slope
produced about 950,000 barrels a day; by 2012, the North Slope
produced a little over 500,000 barrels a day. During this same
time period, production in the U.S. rose and overall the OECD
declined a little bit, although after going down the OECD
responded upward a bit as prices went up after the middle part
of the decade. The U.S. increase has come at the same time as
prices have come up and it has stayed high from 2008 forward.
2:09:54 PM
MR. PULLIAM then compared capital spending [for exploration and
development] between the North Slope, the U.S., and worldwide
[slide 17], saying he again indexed to 2003. From 2003-2006
spending in Alaska and elsewhere in the world was pretty
similar, rising at a similar rate. But a big shift occurred in
2007 when spending in Alaska stayed relatively flat while the
rest of the world jumped up as oil prices went up, including
Prudhoe prices. In 2008, Alaska had a little increase in
spending and the rest of the world had a bigger increase. In
2009, spending in Alaska, the U.S., and worldwide was back
together again as oil prices dropped dramatically. However, as
oil prices came up and stayed high in 2010, 2011, and 2012,
Alaska's spending has stayed about the same while spending
elsewhere really expanded. He clarified this comparison is
limited to exploration and development spending for putting
assets in place to get the oil out of the ground; therefore, the
comparison does not include spending to acquire companies.
2:11:17 PM
MR. PULLIAM moved to reviewing how the ACES tax calculation
works, stating it is important to understand the differences
between ACES and HB 72 [slide 19]. He said ACES is a net tax,
with the tax calculated on the net value of taxable production.
Taxable production is total production minus the royalties. The
net value that is taxed is the gross wellhead value, which is
the West Coast price minus transportation, minus the cost of
production. Costs of production are the operating and capital
costs necessary to pull the oil out of the ground. The base
rate under ACES is 25 percent and this rate applies across the
price spectrum. Additionally, ACES has a progressive rate: as
the taxable value of the oil rises over $30 per barrel, an
additional 0.4 percent of tax is added for each dollar [of
increase]. Another way to think of the progressive tax is to
add 4 percent for every $10 increase. Once the price is over
$92.50 per barrel, the rate becomes 1 percent for every $10.
For example, at a production tax value of $100 per barrel, which
is roughly a West Coast ANS price of $135 per barrel, the base
rate is 25 percent, plus a progressive rate tax of 25.75
percent, for a total tax rate of 50.75 percent. In addition to
the tax, ACES provides a 20 percent credit, taken over 2 years,
against the tax obligation. Small producers have a credit of
$12 million per year that is phased out as a producer's
production increases over 50,000 barrels per day. The state
purchases the credits and net operation losses (NOLs) from those
companies that have no tax obligation - purchasing 45 percent of
capital expenditures and 25 percent of operating expenditures.
The majority of expense for most exploration and development
companies is capital related, he noted.
2:14:30 PM
MR. PULLIAM next reviewed the mechanics for calculating the tax
under ACES and the effective tax rate after credits for 50
million barrels of production at three West Coast ANS price
scenarios: $80, $100, and $120 per barrel [slide 20]. At a
transportation cost of $10 per barrel, the wellhead value would
be $70, $90, and $110, respectively. At operating costs of $15
per barrel and capital costs of $15 per barrel, the taxable
value would be $40, $60, and $80, respectively. The ACES base
tax rate for all three prices is 25 percent. The progressive
tax rate (on the taxable value over the trigger price of $30 per
barrel) is 4 percent at the price of $80, 12 percent at $100,
and 20 percent at $120. [The total tax rate is 29 percent at an
ANS price of $80, 37 percent at $100, 45 percent at $120.] The
total wellhead value is calculated by multiplying the wellhead
value per barrel times the production volume of 50 million
barrels. The total operating and capital expenditures are
calculated by multiplying these per barrel costs times the
production volume of 50 million barrels. The total production
tax value is calculated by subtracting the total operating and
total capital expenditures from the total wellhead value. The
production tax before credits is calculated by multiplying the
production tax value times the [total] tax rate. The production
tax after credits is calculated by subtracting the capital
credit (20 percent times the capital expenditures) from the
production tax before credits. He noted the deduction happens
over a 2-year period, but for simplicity in the example he is
showing it all in one column. The production tax after credits
is thus $430 million at a price of $80, $960 million at $100,
and $1.65 billion at $120, for an effective tax rate after
credits of [21.5] percent, 32 percent, and [41.3] percent,
respectively.
2:17:36 PM
REPRESENTATIVE TUCK surmised taxable value is the same thing as
profit.
MR. PULLIAM concurred taxable value is a proxy for profit.
REPRESENTATIVE TUCK concluded that at a price of $120 per
barrel, making $80 in profit, a company could spend $20 per
barrel more on capital expenditures within the state of Alaska
and drop itself to [$60 in profit] per barrel.
MR. PULLIAM concurred, saying he will show this in a later
slide.
REPRESENTATIVE TUCK further concluded that by investing back
into Alaska, a company can significantly reduce its taxation by
8 percent or more.
MR. PULLIAM confirmed a company can buy down the tax rate by
spending more in Alaska.
2:18:39 PM
REPRESENTATIVE SEATON inquired whether the credit, taken over
two years, is applied to the tax liability as well.
MR. PULLIAM replied the tax liability in a given year is going
to be based on half of a company's capital spending from prior
year plus half of the company's capital spending from the
current year. In the example on slide 20, he is assuming the
putting of those two together, which amounts to $15 a barrel
over the current production, so the company's credit would be
calculated that way.
2:19:39 PM
MR. PULLIAM resumed his presentation, moving to the calculation
of tax under ACES at a West Coast ANS price of $100 per barrel
and varying costs [slide 21]. At [a constant transportation
cost of $10 per barrel] and combined operating and capital costs
of [$20, $35, and $50] per barrel, the effective tax rate after
credits is [38.1 percent, 29.5 percent, and 19 percent,
respectively]. At a West Coast ANS price of $80 per barrel
[slide 22], and the same aforementioned costs of $20, $35, and
$50, the respective effective tax rates after credits are [29
percent, 18.4 percent, and 5 percent].
2:21:11 PM
MR. PULLIAM demonstrated the impact of additional [capital]
spending on the tax obligation under ACES using an example of 50
million barrels of annual taxable production at an initial
expenditure of $1.5 billion plus an additional expenditure of
$250 million [slide 23]. At a West Coast ANS price of $80, the
taxable valuable before that additional expenditure is $40. The
additional expenditure of $250 million amounts to $5 per barrel
of production, reducing the taxable value from $40 to $35. The
tax rate before that additional expenditure is 29 percent, which
is the 25 percent base rate plus 4 percent progressivity. The
tax rate after that additional expenditure drops from 29 percent
to 27 percent because the $5 in additional expenditure reduces
the taxable value from $40 to $35, which reduces the tax rate.
The production tax would then be calculated based on the [27]
percent and the $35 tax value, so a lower tax rate applied to a
lower taxable value after the expenditure. Thus, a $250 million
additional expenditure reduces the tax obligation at $80 per
barrel by about $157 million, a 63 percent reduction; 20 percent
of that is due to the credits and 43 percent is due to the
change in tax obligation prior to the credits. That reduction
increases as the price per barrel increases: at $120 per barrel
the total reduction in taxes after credits rises to $237
million. Thus, the credit remains the same, the spending
remains the same, but at higher prices the amount of the tax
reduction for a given spending gets much higher. At $120 per
barrel the tax obligation is reduced by 95 percent.
2:24:48 PM
CO-CHAIR FEIGE commented "not a bad deal" and asked whether the
spending under ACES leads directly to more production or is
being spent on production.
MR. PULLIAM responded it does not have to be spent on
production, as long as it is a capital expenditure it qualifies
for the credit. An operating expenditure also still qualifies,
but would not get the 20 percent. So, the buy-down effect still
applies whether it is an operating or capital expenditure, but
the additional credits come in for the capital expenditure.
CO-CHAIR FEIGE understood the money the state has been giving
away to companies for credits and reduction in taxes has not
resulted in any further oil for the state to tax down the road.
MR. PULLIAM answered the industry in general is making
investments both in drilling and a lot in facilities. He said
he thinks industry would argue that those investments are all
necessary to support production today and in the future.
However, he continued, the state is providing a significant
piece of that spending.
2:26:14 PM
REPRESENTATIVE TARR inquired whether this same modeling could be
done for a West Coast ANS price of $60 since that was the
approximate price in 2009.
MR. PULLIAM agreed to do so.
2:26:32 PM
REPRESENTATIVE TUCK understood the lower tax rate is based on
the lower tax value. He related that industry talks quite a bit
about lucrative in-field projects. Observing from the chart on
slide 23 that at a price of $80 per barrel, an expenditure
increase of 17 percent reduces the taxation by as much as 63
percent, he asked why more oil is not being produced.
MR. PULLIAM replied people thought this would be a big incentive
when ACES was being put together, but forthcoming slides will
show why this is maybe not the case.
2:27:37 PM
MR. PULLIAM continued his presentation, turning to a graph
[slide 24] excerpted from PFC Energy's 1/31/13 presentation to
the Senate Special Committee TAPS Throughput, which depicts
estimates of capital and operating expense on a per barrel basis
[for projects in Texas, Louisiana, North Dakota, and Alaska].
He noted that the bar depicting capital costs of about $16 for
new light oil in Alaska is pretty consistent with what he used
in his work for this presentation. The bars for capital costs
for mid-high cost development and high cost development in
Alaska depict about [$25] and $34 per barrel, respectively.
2:28:46 PM
MR. PULLIAM next reviewed the effective tax rates for new
development by an incumbent producer with a large amount of
production typical of the legacy fields [slide 25]. For light
conventional oil at a West Coast ANS price of $70 per barrel and
a cost of $16 per barrel, the tax rate after credits is 20
percent on the additional production value; the tax rate after
credits rises to about 50 percent at a price of $140. For high-
cost light oil at a cost of $34, the effective tax rate, or
additional taxes paid on that new production, is negative until
the price rises above $90 per barrel. Another way of looking at
it is that at lower prices the state's tax revenues fall if the
producer makes this investment. Taxes for high cost light oil
do not increase until the price per barrel is over $90, [rising
from -40 percent effective tax rate at a price of $80 to 40
percent effective tax rate at a price of $140].
2:30:42 PM
REPRESENTATIVE SEATON understood that high cost light oil would
be at a base case limitation of 25 percent of profit.
MR. PULLIAM confirmed 25 percent would be the base, but pointed
out that the aforementioned is additive to a producer's existing
production. These areas are going to be places where a producer
will be in a progressivity level anyway, so adding this higher
cost oil will reduce a producer's progressivity and give a
producer credits to apply against that even if the producer is
in a base case.
2:31:57 PM
REPRESENTATIVE SEATON requested an explanation of the minus
percentages shown on the graph for the effective tax rate [slide
25], given there is a 25 percent base case and a producer gets
credits and deductions.
MR. PULLIAM explained the graph is showing the additional tax
that the incumbent would pay as a percentage of the value of the
oil that the company is developing, so that production tax
value. The additional tax is actually negative in these cases
of high cost and low price.
2:33:04 PM
REPRESENTATIVE SEATON presumed if the tax is negative it means
the company is getting money.
MR. PULLIAM replied the company is not getting a refund, just
paying less in taxes.
REPRESENTATIVE SEATON understood, then, that a negative tax
means the company is paying less in taxes than it would be
otherwise. So, not only does the company have the value of the
oil, but it gets to reduce the tax on the rest of its oil.
MR. PULLIAM confirmed it is coming that way and through the
credits provided by the state. He posed a scenario in which a
company starting with a tax obligation of $1 billion makes this
investment and reduces its total tax to $900 million. Thus,
this company's taxes have gone down, the value of the oil that
has been produced has gone up.
REPRESENTATIVE SEATON concluded that the negative is very
positive to the company because it is getting the value of the
oil plus reducing its taxes on all its other oil, meaning the
company has a lot more money in its pocket.
MR. PULLIAM answered correct.
2:34:21 PM
REPRESENTATIVE P. WILSON surmised the companies have therefore
been receiving credits for maintenance costs that they would
have had to do anyway.
MR. PULLIAM replied, "Yes, those investments needed to be made
anyway."
2:34:59 PM
CO-CHAIR SADDLER requested further explanation on how to read
the graph on slide 25.
MR. PULLIAM posed a scenario to explain: A company starts out
owing $1 billion in taxes. It invests in new production. After
making this investment in new production, the company's tax bill
goes down to $900 million. The company has saved $100 million
in taxes, but the value of that new production is positive. The
graphs shows, as a percentage, the incremental tax generated
from this new production. The tax is a percentage of the value
of that new production. If a company's tax goes down, then the
rate is negative. In further response, he agreed to meet with
Co-Chair Saddler later for additional explanation.
2:36:19 PM
MR. PULLIAM resumed his presentation, moving to analysis of
investments in Alaska under ACES relative to investments in the
North Sea, Canada oil sands, and the Lower 48's Eagle Ford and
Bakken. Displaying a graph depicting the production profiles of
these five areas [slide 27], he noted that production for Alaska
and the North Sea look similar: conventional plays that reach
peak production in the first few years and then decline over
time, with a long time period between making an investment to
initial production. However, the Bakken and Eagle Ford, where
much activity is currently being seen, are different: very high
production at the outset that falls off very quickly, with a
very short time period between making an investment to initial
production. The difference in the time period between
investment and initial production is important in how the
economics compare, he explained.
2:37:45 PM
MR. PULLIAM, in response to Representative Tuck, said that wells
in the Eagle Ford and the Bakken can be drilled very quickly,
getting to production very quickly.
2:37:56 PM
REPRESENTATIVE TUCK inquired whether the reason for that is the
seasons and being unable to drill in Alaska year round.
MR. PULLIAM responded it is the seasons, the facilities, and the
availability of the types of rigs. In the Lower 48, much of the
equipment is interchangeable, which is not the case in Alaska.
REPRESENTATIVE TUCK concluded that when looking at what to do
going forward, it must be considered that Alaska has a longer
time period compared to these other investment scenarios that
are being looked at.
MR. PULLIAM answered that is the case relative to the Lower 48,
but less so for the North Sea.
2:38:45 PM
MR. PULLIAM returned to his presentation, noting that the
investment metrics used in the analysis of how Alaska's tax
system stacks up relative to elsewhere included: net present
value (NPV), internal rate of return (IRR), cash
generation/margin, profitability index, and government take, as
well as the net present value of the state's revenues [slide
28]. Information for these metrics is collapsed into the chart
depicted on slide 29, he continued, and details of the
information can be found in the appendix. Information for
Alaska is located to the left side of the vertical line in the
chart and information for all of the other areas is to the right
of the vertical line. Each metric was analyzed at three West
Coast ANS prices: $80, $100, and $120 per barrel. The numbers
in the top line of the chart reflect the net present value (NPV)
of the investment to a producer. He explained that NPV is the
taking of all future positive and negative cash flows and
bringing them back to today at the industry's standard discount
rate of 12 percent. At $80 per barrel, development of 50
million barrels [of light conventional oil] in Alaska would have
a net present value of $2.55 to a new participant and [$3.71] to
an incumbent. The NPV is higher to an incumbent because of the
buy-down effect in progressivity, which a new participant does
not have. Development of 50 million barrels of heavy high cost
oil at $80 per barrel in Alaska [has an NPV of minus $4.51 for a
new participant and minus $2.43 for an incumbent], so it does
not pencil out and would not be undertaken at this price. At a
price of $100 and $120 [the NPV for a new participant is minus
$2.45 and minus $1.09, respectively; for an incumbent the NPV is
positive $2.48 and positive $6.53, respectively]. However,
these positive NPVs for the incumbent producer under ACES come
at a cost to the State of Alaska [of $7.81 at a price of $100,
and a cost of $4.31 at a price of $120].
2:42:55 PM
MR. PULLIAM then drew attention to the NPV figures on the chart
for the Eagle Ford, Bakken, Canada oil sands, Norway, and the
UK. He noted the UK has two different tax rates, one for pre-
1993 fields and a lower one for fields brought into production
post-1993. At $80 per barrel, the NPV of a post-1993 UK
development is $2.41, fairly equivalent to that of a new
participant in Alaska for light oil. The UK's recently
implemented Brownfield Allowance greatly increases the
attractiveness of investment, with the NPV rising to $4.62 at a
price of $80. At a price of $100 for light oil, Alaska projects
do not stack up as well for a new participant as compared to the
benchmark areas; for an incumbent participant the projects are
more in line with the other areas but not as attractive as the
UK brownfield. At a price of $100 for heavy oil, the NPV of
$2.48 for an incumbent in Alaska does not look so attractive
when compared to that of the other areas. So, while ACES
increases the attractiveness of heavy oil in Alaska, it does not
pencil out when an incumbent looks at what is available
elsewhere at a price level of $100.
2:45:26 PM
MR. PULLIAM, still referencing the chart on slide 29, he further
noted that the profitability index, internal rate of return,
cash margins, and government take are other important things the
producers look at when making investments. The takeaway from
the chart is that the economics are probably not yet quite right
for Alaska heavy oil. For light oil, the economics under ACES
are not great relative to opportunities elsewhere, particularly
for new participants. Beside low NPVs, the cash margins for
both new and incumbent participants in Alaska are not generally
as attractive as elsewhere. Additionally, Alaska's government
take is fairly high, particularly for a new participant. For
someone wondering why Alaska does not have more activity and
more companies participating, he would suggest that Alaska does
not look attractive relative to much of the rest of the world.
2:47:16 PM
MR. PULLIAM, in response to Representative Tarr, confirmed that
the government take depicted on slide 29 includes the top
federal tax rate of 35 percent.
REPRESENTATIVE TARR requested Mr. Pulliam to provide examples of
how a producer could affect its federal tax rate based on its
investments in Alaska.
MR. PULLIAM replied he could break down the take by state and
federal, but advised that it is irrelevant from the investors'
standpoint because the investors are interested in what they
will walk away with. Alaska has no control over what that
federal rate is. While it is true that tax paid to the state is
deductible from the federal tax, the investor does not care
where it is going when it is going someplace besides the
investor's pocket.
2:48:28 PM
REPRESENTATIVE SEATON understood the aforementioned chart
encompasses every kind of tax, including Alaska's 9.4 percent
corporate income tax. He pointed out, however, that a company's
effective corporate income tax rate could be 6.6 percent.
MR. PULLIAM responded he used 6.5 percent in the analysis, given
that is closer to what the companies effectively pay.
REPRESENTATIVE SEATON presumed the [state/municipal NPV] is not
included [for the benchmark areas] because it is included within
the percent of government take.
MR. PULLIAM confirmed it is in the total government take. He
said he included the state/municipal NPV for Alaska so it could
be seen how Alaska's system works for the state.
REPRESENTATIVE SEATON inquired whether private royalties are
included in the government take section for the Eagle Ford and
Bakken areas.
MR. PULLIAM confirmed the government take is generically used
for all royalties and taxes, and said it is correct that in the
Eagle Ford and Bakken areas most of the production is from
private lands and subject to private royalties.
2:50:22 PM
MR. PULLIAM continued his presentation, stating that even under
ACES the economics of high cost heavy oil development are not
yet quite right [slide 30]. Referring to the top left chart on
the slide, he said that as prices climb above $90 the net
present value for an incumbent is positive under ACES, rising to
nearly $8 per barrel and then tapering off. But for the state
(bottom left chart), the NPV is negative as a result of the buy-
down and a result of the credits going out. He said he
therefore looked to see if there was a system the state could
put in place that would help make that a better deal. He found
that even if the state had no taxes and no credits the NPV for
high cost heavy oil is still not very attractive until very high
price levels. However, he qualified, that is for today; it
could be different in the future as technology advances making
it cheaper and easier to get at heavy oil. But, right now, even
a no-tax system probably would not bring on some of that heavy
oil. Moving to slide 31, Mr. Pulliam noted that the economics
for high cost light oil development are a little bit better than
for heavy oil, but still not yet quite ripe even with no taxes.
The state could pay companies to produce by giving credits, but
that may not be something the state wants to be doing.
2:53:19 PM
MR. PULLIAM next looked at projected cash generation from other
jurisdictions and ongoing North Slope production under ACES,
based on the Department of Revenue's production forecast for the
period 2017-2021 [slide 32]. He explained the chart depicts
what would happen if investment was made today to bring on this
production. As the price of oil goes up, the cash generation
under ACES is not as attractive as it is in [Canada, Eagle Ford,
Bakken, Norway, and the UK]. This is a result of Alaska's cost
structure and the progressivity, he said.
2:54:14 PM
REPRESENTATIVE SEATON asked whether the line on the chart for
ACES assumes no buy-down on the tax rate by re-investment
MR. PULLIAM answered there is some buy-down going on in the
depiction because it assumes a continued level of investment and
operating cost in Alaska and the advancing of new investments
coming on. The line depicting ACES is done as an overall slope
number, so it assumes a projection of the new investments that
are going to be taking place in this time period.
2:55:02 PM
REPRESENTATIVE SEATON said the current system was designed to
stimulate investment because prior to PPT and ACES there was not
the level of investment that Alaska wanted to see. He said he
is asking whether the analysis was done looking at investment in
the status quo or looking at a stimulation of investment. If it
considered stimulation in investment then it would also include
the corresponding credits the state is paying out. Given the
state is paying out a billion dollars in credits per year, he
maintained that increased investment appears to be happening.
MR. PULLIAM clarified that [slide 32] is for the producers, not
the State of Alaska. The graph looks at the cash that producers
would expect to take out of Alaska assuming all of that activity
occurs, so it does assume credits in there as well. This goes
to Representative Tuck's question, he said. Why is Alaska not
getting what was hoped for out of the ACES system? He suggested
one reason is that when companies look at their Alaska
operations, they see what is shown on this chart - Alaska does
not generate a lot of cash relative to what the company can do
elsewhere. That is an important aspect for companies that are
looking to pay shareholders and to provide funds for
reinvestment, he stressed.
2:57:08 PM
CO-CHAIR SADDLER asked whether the cash margin per barrel
depicted on the graph is the same as profit per barrel.
MR. PULLIAM responded it is different than profit; it is the
amount of cash that the producer gets. It is profit with
depreciation added back in, which is an expense against profit
and which is not an outflow of cash. It is a deduction when
calculating a company's accounting profit. When looking at what
a company's cash flow is, that deduction is added back in.
2:57:46 PM
REPRESENTATIVE SEATON returned to slide 29 and observed the 5-
year cash margins for new and incumbent producers in Alaska
compared to the Eagle Ford. He asked why the cash margins
depicted on the chart on slide 32 are lower than the numbers
shown on slide 29.
MR. PULLIAM answered that the slides are two different pieces of
analysis. The table on slide 29 looks at the economics of a new
investment; it looks at just that investment on a stand-alone.
The graph on slide 32 looks at cash flow for the whole North
Slope for this [same time period of 2017-2021], so it is more
than just the new investment and is across all operations - both
ongoing and new. In further response, he said the difference in
the two is that [slide 29] is for a single investment whereas
[slide 32] is the cash flow for all ongoing operations so there
is melding that is going on. He agreed to provide further
explanation to Representative Seaton at a later time.
3:01:47 PM
CO-CHAIR FEIGE announced the committee would stand in recess
until 3:30 p.m. [HB 72 was taken up again at 7:49 p.m. this
same day.]
3:35:14 PM
CO-CHAIR SADDLER reconvened the House Resources Standing
Committee meeting. Representatives Hawker, Seaton, P. Wilson,
Olson, Feige, and Saddler were present at the call back to
order. Representatives Johnson, Tarr, and Tuck arrived after
the call back to order. Representative Chenault was also
present.
HB 4-IN-STATE GASLINE DEVELOPMENT CORP
3:35:27 PM
CO-CHAIR SADDLER announced that the next order of business would
be SPONSOR SUBSTITUTE FOR HOUSE BILL NO. 4, "An Act relating to
the Alaska Gasline Development Corporation; making the Alaska
Gasline Development Corporation, a subsidiary of the Alaska
Housing Finance Corporation, an independent public corporation
of the state; establishing and relating to the in-state natural
gas pipeline fund; making certain information provided to or by
the Alaska Gasline Development Corporation and its subsidiaries
exempt from inspection as a public record; relating to the Joint
In-State Gasline Development Team; relating to the Alaska
Housing Finance Corporation; relating to the price of the
state's royalty gas for certain contracts; relating to judicial
review of a right-of-way lease or an action or decision related
to the development or construction of an oil or gas pipeline on
state land; relating to the lease of a right-of-way for a gas
pipeline transportation corridor, including a corridor for a
natural gas pipeline that is a contract carrier; relating to the
cost of natural resources, permits, and leases provided to the
Alaska Gasline Development Corporation; relating to procurement
by the Alaska Gasline Development Corporation; relating to the
review by the Regulatory Commission of Alaska of natural gas
transportation contracts; relating to the regulation by the
Regulatory Commission of Alaska of an in-state natural gas
pipeline project developed by the Alaska Gasline Development
Corporation; relating to the regulation by the Regulatory
Commission of Alaska of an in-state natural gas pipeline that
provides transportation by contract carriage; relating to the
Alaska Natural Gas Development Authority; relating to the
procurement of certain services by the Alaska Natural Gas
Development Authority; exempting property of a project developed
by the Alaska Gasline Development Corporation from property
taxes before the commencement of commercial operations; and
providing for an effective date."
3:36:06 PM
RENA DELBRIDGE, Staff, Representative Mike Hawker, Alaska State
Legislature, continued her sectional analysis of SSHB 4 on
behalf of the joint prime sponsors, Representatives Chenault and
Hawker. She said SSHB 4 proposes a regulatory framework and
highlighted reasons why the state regulates. The legislature
decides if something should be regulated, how it should it be
regulated, and who should regulate it, she explained. Generally
speaking, the legislature has delegated that regulation to the
Regulatory Commission of Alaska (RCA) for public utilities in
the state and for oil and gas pipelines. There are overall good
reasons to regulate something that provides a service to people,
especially when there is little competition to provide that
service. Thus, regulation protects the provider of the service,
the consumers of the service, and members of the public when the
public has a benefit from that service.
3:37:55 PM
MS. DELBRIDGE pointed out the particular things the RCA does
when regulating. The RCA certifies that someone wanting to
provide a service is qualified to do so. The RCA ensures that a
provider offers safe, adequate services and facilities, and that
those services are provided at reasonable rates, terms, and
conditions. The RCA also ensures that while providing for
reasonable rates, the service provider has an opportunity to
make a reasonable rate of return on its investment in providing
that service. The RCA looks out for people needing access to
that service by ensuring there is not undue discrimination in
charges and in services. The RCA ensures that the carrier has
enough financial ability to provide the service it is asking to
provide. The RCA further provides a structure through
regulation so the carrier can set out contract terms and provide
changes to those terms as circumstances change over time.
3:38:54 PM
MS. DELBRIDGE reminded members of the need for an Alaska Gasline
Development Corporation (AGDC) pipeline to operate as a contract
carrier. Alaska currently has no regulatory framework for an
in-state gas pipeline that operates as a contract carrier. Thus
SSHB 4 creates that framework, essentially giving the RCA a new
class of pipelines to regulate - contract carrier gas pipelines.
This proposed regulatory structure applies to any contract
carrier gas pipeline, not just AGDC, and applies only to gas,
not oil, pipelines. This proposed regulatory structure does not
apply to a pipeline that falls within a federal regulatory
jurisdiction, such as that of the Federal Energy Regulatory
Commission (FERC). Further, a pipeline regulated under this new
contract carrier chapter is exempt from regulation under other
regulatory chapters. Also included in SSHB 4 are housekeeping
sections needed by the RCA in the chapters under which it
regulates. These tell the RCA it can do the regulating job the
legislature has told it to do, such as appointing panels to hear
matters and including in an annual report its regulatory
activities under a given chapter.
3:40:32 PM
MS. DELBRIDGE directed attention to the new regulatory structure
specifically proposed by SSHB 4, starting with Section 29, page
38, through the end of Section 33, page 51. She related that
over the past year and a half, the sponsors worked closely with
AGDC and with the Department of Law attorneys assigned to the
RCA to structure this framework. She related that the RCA told
the sponsors it was very important to be clear in how the
legislature would like it to regulate and to then give the RCA
the direction and authority to carry out that regulation. This
section is not perfect, she said. The sponsors are still
talking with attorneys assigned to the RCA and with the
administration to ensure the appropriate accountability is
included in the bill to protect all parties involved.
3:41:53 PM
MS. DELBRIDGE reviewed the provisions of SSHB 4 that empower the
RCA, paraphrasing from the sectional analysis [original
punctuation provided]:
Section 29 (RCA, conforming), amends AS 42.04.080(a),
Public Utilities and Carriers and Energy Programs,
Regulatory Commission of Alaska, Decision-making
procedures, to allow the RCA to appoint a panel for
hearing matters under the new 42.08.
The RCA needs the statutory authority to appoint a
panel and hear a matter that comes before them under
one of two existing regulatory statutes. This adds the
new regulatory chapter created in HB 4, 42.08, to that
statutory direction, so the RCA will be able to act on
matters that come up under the new regulatory chapter.
Section 30 (RCA review of public utility contracts),
amends AS 42.05, Public Utilities and Carriers and
Energy Programs, Alaska Public Utilities Regulatory
Act, by adding a new section related to RCA review of
contracts entered into by a public utility with AGDC
for transportation or for contracts public utilities
sign to purchase gas or store gas transported on an
instate natural gas pipeline regulated under 42.08.
Public utility contracts with AGDC may include a
covenant for public utilities to collect rates
sufficient to meet contractual obligations. Contracts
to buy or store gas to be shipped on an instate
natural gas pipeline regulated under 42.08 must be
submitted to the RCA before they take effect. The RCA
has 180 days to disapprove contracts as presented or,
if contracts are found not just or reasonable, to
disapprove the contracts. Contracts approved are not
subject to further RCA review. The RCA may extend the
180 day review period if a public utility fails to
provide supplemental information that is available to
the public utility.
This section provides an interface between regulation
of public utilities, and regulation of a contract
carrier natural gas pipeline. If the RCA approves a
contract involving a utility and the pipeline carrier,
the utility has assurances that it will be able to
recover its costs in rates charged to utility
customers.
Section 31 (RCA conforming) amends AS 42.05.711,
Public Utilities and Carriers and Energy Programs,
Alaska Public Utilities Regulatory Act, Exemptions, to
exempt a pipeline subject to regulation under 42.08
from regulation under 42.05.
Section 32 (RCA conforming) amends AS 42.06, Public
Utilities and Carriers and Energy Programs, Pipeline
Act, by adding a new section to article 7 exempting a
pipeline subject to regulation under 42.08 from
regulation under 42.06.
3:42:23 PM
MS. DELBRIDGE elaborated on Section 30, explaining that the
provisions are like a pre-approval process, which more and more
utilities are shifting towards. For example, when embarking on
its extensive Southcentral Alaska power project, Chugach
Electric Association, Inc. sought pre-approval from the RCA for
that expenditure so the utility would know the money it invested
in these upgrades and new facilities would be "certified" as
things the RCA knew needed to happen and that the utility could
pass on [to consumers]. Similar to this was the Cook Inlet
Natural Gas Storage Alaska, LLC (CINGSA) facility, where the RCA
essentially granted utilities pre-approval so they would know
that if they paid for storage the expense could be passed on to
consumers. Under Section 30 a contract between a utility and
AGDC can include a covenant that the public utility will be able
to recover its costs in the rates charged to consumers. This is
a good backstop for protecting consumers, as well as protecting
the electric and gas utilities that will hopefully be
participating in this pipeline.
3:45:00 PM
REPRESENTATIVE TUCK inquired whether this proposed structure is
identical to an existing gas utility.
MS. DELBRIDGE replied the structure is very different. The RCA
currently regulates gas or other public utilities under AS
42.05, Public Utility Regulation. The RCA can also regulate
pipelines under AS 42.06, the Pipeline Act, which addresses oil
pipelines or common carrier pipelines. Thus, SSHB 4 creates AS
42.08 for contract carrier in-state gas pipelines. Section 30
of the bill is the interface between this new structure and the
way the RCA already regulates public utilities for tariff rates
that can be passed on to consumers.
3:46:01 PM
REPRESENTATIVE TUCK posed a scenario in which ENSTAR purchases
gas from a supplier that is shipping on this pipeline. He asked
whether RCA will have jurisdiction over this purchase.
MS. DELBRIDGE responded the RCA will have jurisdiction over all
shipping contracts on the AGDC pipeline. If ENSTAR procures a
supply of gas from a producer in Cook Inlet, the RCA does not
necessarily have to approve that supply contract, but the RCA
does approve the second part where ENSTAR gets the gas to its
customers. When, in delivering gas to its utility customers,
ENSTAR looks to recover its costs of getting the gas in the
first place, the RCA must go by the best information that ENSTAR
and the producer had a reasonable agreement for that. ENSTAR
might ship gas on the pipeline or it might buy gas that was
shipped by someone else on the pipeline, so its contract might
not be with AGDC for shipment. However, if ENSTAR has a related
contract, SSHB 4 allows another level of RCA review of those
contracts so the utility has assurance that it will be able to
cover those costs later.
3:47:46 PM
REPRESENTATIVE SEATON charged that the RCA's gas distribution
regulation is not at all transparent. He said the RCA does not
seek to limit costs and many times the tariffs are agreed to by
stipulation, thereby preventing the public from getting the
background information from the RCA. Two cities he is dealing
with are having this problem with gas distribution systems, he
related. Two years ago there was $1.21 in unallocated labor
costs per foot of line being put in, which increased to $21.00
the next year, but backup and justification information cannot
be accessed because the tariff was adopted by stipulation. He
urged a provision be put into SSHB 4 requiring that background
information for stipulated tariffs be made publically available
and maintained by the RCA. Rather than regulating and looking
at the costs as it is supposed to do, the RCA acts like an
adjudicatory authority. When one utility is objected to by
another, the lawyers argue it out in front of the RCA and the
RCA makes a decision, but all the background material then
becomes confidential and is held by those separate companies.
He said he wants to ensure that this same system is not put in
place [under SSHB 4] because it is a way for data that is
supposed to be public to be hidden by the RCA process. Given
SSHB 4 is a work in progress, it must be ensured going forward
that if the public has questions about those contracts or
distribution of that gas there is a way to find it. Clear
criteria must be developed that things must be maintained
transparently in the new RCA regulations.
3:51:24 PM
REPRESENTATIVE OLSON inquired whether anyone from the RCA is
online.
CO-CHAIR SADDLER replied there is not today but the plan is to
have someone from the RCA talk to the committee at some point.
MS. DELBRIDGE stated the Department of Law attorney for the RCA,
Stuart Goering, is following the hearings and paying close
attention, and would be glad to answer questions at the
appropriate time.
3:52:15 PM
MS. DELBRIDGE, continuing the sectional analysis, explained that
Section 33 lays out the new structure for regulating an in-state
natural gas pipeline. She paraphrased from the sectional
analysis [original punctuation provided]:
Section 33 (RCA natural gas pipeline contract carrier)
adds a new chapter to AS 42, Public Utilities and
Carriers and Energy Programs, to create Chapter 08,
In-state Pipeline Contract Carrier. Chapter 08 applies
to an instate natural gas pipeline providing contract
carriage, and exempts an in-state natural gas pipeline
subject exclusively to federal jurisdiction.
House Bill 4 provides for a new category of gas
pipeline carriage, contract carriage, and includes a
new regulatory framework for a contract carrier gas
pipeline. The new 42.08 is a shift from traditional
cost-based regulation, and directs the Regulatory
Commission of Alaska to instead evaluate whether
negotiated contracts are fair and reasonable. Checks
and balances are included to set basic rules ensuring
fair and open processes; to promote exploration and
development of Alaska's gas basins; to protect the
public welfare; and to require heightened scrutiny for
contracts entered into by affiliated parties.
MS. DELBRIDGE noted this is the only place in this regulatory
structure in which special qualifications are included just for
AGDC. She continued paraphrasing [original punctuation
provided]:
Sec. 42.08.010, Application of chapter; exemption,
applies this chapter to an instate natural gas
pipeline providing service as a contract carrier.
Exempts an instate natural gas pipeline subject
exclusively to federal jurisdiction.
Sec. 42.08.020, Qualification of the Alaska Gasline
Development Corporation; findings, determines that
AGDC is financially and managerially fit, willing and
able to provide service under 42.08. States that an
AGDC pipeline is required by public convenience and
necessity. Directs the RCA to determine whether any
entity applying under 42.08 is technically fit,
willing and able.
The findings made on behalf of the RCA in this section
are findings that the RCA usually needs to make in
issuing a pipeline building permit - a Certificate of
Public Convenience and Necessity. The advance findings
are not valid for an applicant other than AGDC. For
AGDC and any applicant, the RCA will need to determine
whether the entity is technically able to build the
project and provide the service proposed.
3:54:29 PM
MS. DELBRIDGE moved to review of the general instructions to the
RCA in Section 33, paraphrasing [original punctuation provided]:
Sec. 42.08.220, General powers and duties, provides
enabling direction for the RCA under 42.08. Requires
permits for construction, interconnections, expansions
and abandonment. Enables the RCA to intervene in
disputes that where not accounted for in contractual
dispute resolution mechanisms, and that threaten the
public safety and welfare. Prohibits the RCA from
requiring rates or tariff regulations, except as
provided in the chapter, and from conducting further
review of contracts approved under 42.08.
3:56:35 PM
REPRESENTATIVE SEATON understood AGDC will be negotiating tariff
rates with particular utilities. He asked whether "prohibits
the RCA from requiring rates or tariff regulations" means the
RCA really has no authority on requiring those tariffs or rates.
MS. DELBRIDGE responded a regulatory body can regulate using a
cost-based approach or can regulate contracts that use a
negotiated rate type approach. Typically, in some cases, the
RCA has been able to decide what rates might be. Because SSHB 4
sets up the structure for an in-state gas contract carrier
pipeline, it is trusting to contracts to create rates that are
reasonable for the parties entering the contracts. Thus, the
RCA would no longer need to go in and make the rates.
3:57:52 PM
REPRESENTATIVE SEATON posed a scenario in which AGDC is not the
full financial contributor and the pipeline is built primarily
by private enterprise. He asked whether in this situation the
RCA would have input on the rate of return. He further asked
what the RCA's duty and power would be in looking out for the
public interest in those negotiated rates.
MS. DELBRIDGE answered the public interest can be defined as,
one, the people using gas provided by public utilities or, two,
the people shipping on an AGDC pipeline, i.e. AGDC's customers,
which may or may not be gas that goes to public utilities. For
a shipper with a contract for gas that is not going to a public
utility, this chapter essentially says that as long as there was
no duress or fraud or an affiliate relationship between those
parties, then that contract is just and reasonable because two
people said "this is the price we are willing to sell/this is
the price we are willing to pay". If a public utility is
involved, there is this additional standard of review that
essentially requires the RCA to give a deeper look to the pre-
approval that the utility will be able to pass that on to its
customers.
3:59:39 PM
REPRESENTATIVE SEATON noted that with FERC there is a generally
approved rate of return. However, given SSHB 4 is for contract
carriage, he asked whether there is anything in the bill that
prevents a negotiated rate of return of 25 percent.
MS. DELBRIDGE replied it will be seen in later discussion that
the carrier must start with a recourse rate, which is a rate
available to any shipper on the pipeline as a starting point for
negotiation. The recourse rate is supported by a cost-of-
service study that includes a rate of return. The RCA standard
of review includes making sure that negotiations from that
[starting] recourse tariff are done so in a reasonable way.
4:00:51 PM
CO-CHAIR SADDLER understood the starting point is based on a
reasonable rate of service, but inquired whether there is
anything to prevent a contractual agreement between the shipper
and the pipeline owner from having a generous rate of return.
MS. DELBRIDGE responded [the shipper] entering into the contract
will be able to see the rate of return being proposed by the
carrier. To some extent, it is highly unlikely that [a shipper]
would sign a contract that creates a 20 percent rate of return
for the carrier. She said SSHB 4 provides a much higher level
of scrutiny for contracts that are between affiliates; it
essentially reverts to the RCA's standard level of review under
AS 42.06, Pipeline Act, which goes into a full rate-based study.
4:02:37 PM
TINA GROVIER, Attorney, Natural Resources and Energy Law, Birch
Horton Bittner & Cherot, Counsel to Alaska Gasline Development
Corporation (AGDC), confirmed Ms. Delbridge's aforementioned
statement to be correct.
4:02:57 PM
REPRESENTATIVE SEATON requested Ms. Grovier to re-state the
issue and elaborate on why Ms. Delbridge is correct.
MS. GROVIER understood the concern is about affiliated entities
and whether there is a tool in SSHB 4 for the RCA to take a
closer look at that. She directed attention to page 45, lines
3-8, which state that if the parties are affiliated and it is
not an arms-length transaction, then "the commission shall
determine whether the precedent agreement or related contract is
just and reasonable using the standards normally applied under
AS 42.06.140", which is the existing RCA common carriage statute
that regulates pipelines.
4:04:37 PM
MS. DELBRIDGE requested Ms. Grovier to address whether the rate
of return that a pipeline carrier creates for itself is limited,
or can the carrier sign contracts giving itself a 20 percent
rate of return that the RCA has no review over regardless of
whether the parties are affiliated.
MS. GROVIER answered that, as she understands it, the recourse
tariff being filed will specify the rate of return in the cost-
of-service study. If the RCA is reviewing that recourse tariff,
that is the opportunity where that would be reviewed.
4:05:33 PM
REPRESENTATIVE SEATON understood the tariff is to pay back the
people who have firm shipping contracts. If that is the case,
will they be receiving a return on that investment, he asked.
MS. DELBRIDGE replied the pipeline will do its work over the
next few years and before recruiting shippers it will do a cost-
of-service study that contains a massive list of things,
including its rate of return opportunity. The study is the
foundation for the rate and the rate is part of the tariff.
Also part of the tariff is all the other terms and conditions of
service. For some shippers, having a greater volume available
is more important than the rate, so there is room to negotiate
some of the terms. The tariff, to start with, is called a
recourse tariff. This recourse tariff goes to the RCA and all
potential shippers, providing a starting point that is eligible
for everybody to play on. Because no one wants to pay more than
is reasonable, the cost-of-service study must support the
elements in the tariff. During the open season the carrier is
asking shippers to buy space in the pipeline. The recourse
tariff is the starting point and the fine points are then
negotiated because different shippers have different priorities;
for example, a shipper may be willing to have its service
interrupted at times in return for a better rate. The hope is
that the negotiations end up with a precedent agreement and that
precedent agreement would include the negotiated rates and the
negotiated terms and conditions. Those precedent agreements are
the contract and that contract has some conditions attached to
it, such as the carrier needs to ensure its project is within a
certain cost range, must start operations by a certain date,
must obtain certain permits, or any number of things. For the
next year or two after signing the precedent agreements and
filling up the pipeline during open season, work is begun on
resolving the conditions. Once the conditions have been met and
the financing is there, the precedent agreements are turned into
firm transportation agreements and that is when the project is
sanctioned and construction begins.
4:10:07 PM
REPRESENTATIVE SEATON said the concern he is trying to get at is
when the shippers are actually the financiers or the owners of
the pipeline or owners of major pieces of the pipeline, the
Trans-Alaska Pipeline System (TAPS) being an example. He said
he wants to ensure that the structure of SSHB 4 will ensure the
tariffs are as low as they can be for generating a generous
return to the financiers.
MS. DELBRIDGE understood the concern and said she will point out
where those extra levels of precautions have been made as she
goes along in her review. She acknowledged the possibility for
shippers to be potential owners, as with any pipeline, and said
the bill has additional backstops for this. That is also where
the firewalls come into play, she continued; for example, "BP
Producer" and "BP Pipeline Company" cannot give themselves
unfair advantages either. If the pipeline is being financed
through revenue bonds, the people rating those bonds and then
financing the pipeline are going to take a very, very good look
at these contracts to ensure it is a legitimate investment for
them to make; part of that is whether the financier has a chance
to earn a reasonable rate of return.
4:12:50 PM
MS. DELBRIDGE, responding to Co-Chair Saddler, said Section
42.08.220 is on page 29 of the bill. Resuming her review, she
paraphrased from the sectional analysis [original punctuation
provided]:
Sec. 42.08.230, Commission decision-making procedures,
directs the RCA to appoint a panel to consider and
decide matters under 42.08, and to expeditiously
adjudicate matters.
Sec. 42.08.240, Publication of reports, orders,
decisions and regulations, is the standard RCA
direction for publishing reports, orders, decisions
and regulations.
Sec. 42.08.250, Application of Administrative
Procedure Act, is the standard RCA exemption from
Administrative Procedure Act adjudication procedures.
Instead, the RCA's adjudication procedures would
apply. The rest of the Administrative Procedures Act
still applies to regulations adopted by the RCA.
Sec. 42.08.260, Annual report, requires the RCA to
include in its annual report activities related to
42.08.
Sec. 42.08.300, Open seasons, sets rules a carrier
must follow when holding an open season. Provides
parameters for holding an open season to ensure
fairness and openness for all interested potential
shippers, including advance notice. Requires a carrier
to hold an open season for pipeline expansion when the
carrier has received requests for firm service from
potential shippers that would enable a commercially
reasonable expansion. Provides that expansions may not
violate the terms of AGIA. Allows a carrier to make
pre-subscription agreements before an open season
begins. Requires a carrier to award firm
transportation service without undue discrimination or
preference.
4:14:02 PM
MS. DELBRIDGE elaborated that the advance public notice required
by Section 42.08.300 must include the recourse tariff, the
proposed form the agreements will take in the end, and
information about such things as pipeline route, capacity,
operating pressures, and quality specifications. The notice
must also be clear as to how the carrier is going to allocate
capacity to the bidders. Any pre-subscription agreements before
an open season begins would still be based on the recourse
tariff.
4:16:06 PM
CO-CHAIR SADDLER inquired who would make the determination that
an expansion is commercially reasonable.
MS. DELBRIDGE answered the determination would be presented
through the RCA. If there was any question as to whether the
opportunity was commercially reasonable, an arbitrator would be
there to decide that.
4:16:32 PM
MS. DELBRIDGE turned back to paraphrasing from the sectional
analysis [original punctuation provided]:
Sec. 42.08.310, Transportation service, provides that
firm service can only be made available through
presubscription agreements or open seasons. Requires a
carrier to offer a recourse tariff with rates
determined on a cost-of-service basis. Allows that
negotiated firm transportation rates may be different
from recourse rates. Requires a carrier to provide
interruptible service in capacity not used in firm
service.
MS. DELBRIDGE explained a carrier must provide a recourse tariff
developed from a cost-of-service basis. The carrier must be
able to roll in rates for expansion, so long as resulting rates
for the current shippers do not exceed the maximums under their
contracts. The carrier must file the recourse tariff with the
RCA. Starting with that recourse rate, AGDC and each potential
shipper can negotiate the rates, the terms, and conditions for
that given contract. She said this section also requires that
things be done fairly. So, AGDC can negotiate, but it has to do
so keeping in mind that that next level of RCA oversight is
going to ensure that these negotiations were done fairly and
that they are responsible and non-discriminatory. The earliest
contracts must include a dispute resolution procedure. Section
42.08.310 also requires the carrier to provide interruptible,
maybe short-term service, for any capacity that is not being
used in firm service. For example, gas and oil fields might go
through seasonal shutdowns for maintenance, leaving capacity
available that could be filled during that shutdown period.
4:18:58 PM
REPRESENTATIVE TARR, returning to Section 42.08.300, asked how
"holding an open season to ensure fairness and openness for all
interested potential shippers" and "pre-subscription agreements"
work together to ensure fairness for all interested parties.
MS. DELBRIDGE replied a carrier will be negotiating privately
with different shippers, whether in a pre-subscription agreement
or in an open season, and both opportunities must start with
that recourse tariff. The contracts coming out of these will
all be managed the same way - as precedent agreements going
forward.
4:20:00 PM
REPRESENTATIVE SEATON inquired whether the negotiated tariffs in
the contracts are generally lower than the recourse rate based
on cost-of-service.
MS. DELBRIDGE responded she thinks it might be the opposite, but
deferred to a representative from AGDC for an answer.
4:20:35 PM
DARYL KLEPPIN, Manager, Commercial Team, Alaska Gasline
Development Corporation (AGDC), Alaska Housing Finance
Corporation (AHFC), Department of Revenue (DOR), understood the
question to be whether a rate negotiated off the recourse tariff
could be lower than the recourse tariff. He said the answer
would be yes, depending upon other terms and conditions as there
are a lot of other issues besides the rate that a [shipper] may
find important and may be willing to pay more or less depending
upon those terms and conditions.
4:21:14 PM
REPRESENTATIVE SEATON pointed out that if negotiations can be
for a tariff that is higher than a recourse rate that is based
on cost of service and a fair rate of return, then that will be
a cost to the consumers or whoever is on the other end of the
pipe. He asked whether the potential here is for a higher rate
or a lower rate and said it raises some concern if it is higher
than the cost-of-service tariffs with no limitation.
MS. DELBRIDGE answered she thinks this is getting to the review
of certain contracts by the RCA in which the RCA looks at how
far above or below that recourse tariff the parties went and how
that rate change was compensated for with other terms and
conditions that are of value. For example, a utility shipper
might feel that a long-term supply of gas is worth a little bit
more than having less gas than it thinks it is going to need and
paying less. There is a value in having certain terms and
conditions met, she said, the price is not everything.
4:23:00 PM
REPRESENTATIVE SEATON stated he is trying to understand why a
shipper would bid for a higher tariff, although a shipper might
bid for a higher price from the seller. He suggested getting
together for further explanation later.
MS. DELBRIDGE agreed to do so.
CO-CHAIR SADDLER surmised the recourse rate sets the benchmark
from which to negotiate depending on other terms and conditions.
MS. DELBRIDGE replied correct and added that it is fairly common
to let the rate fluctuate a little bit because a benefit is
being gained in the terms and conditions.
CO-CHAIR SADDLER commented the provisions are that the contracts
are reviewable.
4:23:58 PM
MS. DELBRIDGE continued her review, paraphrasing from the
sectional analysis [original punctuation provided]:
Sec. 42.08.320, Review of certain contracts by the
commission, requires a carrier to submit all precedent
agreements to the RCA; precedent agreements with other
than a public utility may be kept under seal. The RCA
has 180 days to approve or disapprove precedent
agreements as just and reasonable. Sets the standard
for determining if a contract is made at arm's length
and allows additional RCA scrutiny of contracts made
between affiliated parties that are not substantially
similar to transactions made between unaffiliated
parties. Approved contracts are not subject to further
review.
MS. DELBRIDGE noted Section 42.08.320 has a decision tree: the
RCA looks at the contract and if it was done at arm's length
between two parties, this structure says that that contract is
just and reasonable unless the RCA finds that there was some
kind of unlawful activity or fraud. If a contract was made at
arm's length it is good to go. However, it must be decided what
makes it arm's length. Under SSHB 4, a contract is arm's length
if it incorporates the recourse tariff.
4:25:23 PM
CO-CHAIR SADDLER inquired whether a contract below the recourse
rate will automatically be considered not at arm's length.
MS. DELBRIDGE responded such an agreement would be considered as
not meeting that standard of incorporating the recourse tariff.
[Citing from page 44, lines 27-31, and page 45, lines 1-13 of
SSHB 4], she said an agreement that does not include the
recourse tariff would be considered arm's length if it is
between two state-owned parties or between private parties that
are not affiliated. An agreement between two affiliates would
be considered arm's length if substantially similar to contracts
made between unaffiliated parties. An agreement between
affiliates that is not substantially similar to other contracts
would not be at arm's length, so the RCA would conduct a higher
level of review of that contract.
4:26:25 PM
CO-CHAIR SADDLER asked who within the RCA would make these
evaluations, decisions, and judgments.
MS. DELBRIDGE believed the RCA as a whole would use its existing
procedure, but said she is unsure whether that includes the
whole commission or an administrative law judge. Often the
commission begins hearing a matter and then delegates the follow
through to an administrative law judge.
4:26:57 PM
REPRESENTATIVE P. WILSON read page 44, lines 24-26 of the bill,
which state "a contract that is approved or considered approved
under this paragraph and the associated firm transportation
agreement are not subject to further review by the commission."
She noted this is stated more than once and asked why.
MS. DELBRIDGE replied it was important to structure a regulatory
framework that honored that contracts could be made between two
parties to ship gas on a pipeline. Having a third party that
can keep coming back to review that contract negates the concept
that contracts freely entered into by people that are not under
fraud are fair.
4:27:51 PM
MS. DELBRIDGE resumed the sectional analysis, reiterating that
if a contract is not at arm's length, the RCA will go into a
much deeper level of review and will use the same standards that
it would apply in reviewing a contract under the Pipeline Act,
which is existing regulation for common carrier pipelines,
allowing the RCA to actually make just, fair, and reasonable
rates or to require those. She said Section 42.08.320 is clear
that the carrier must provide the RCA with a cost-of-service
study so that the RCA actually has the tool it needs to do this
extra level of review. The section further provides that when
contemplating approving or disapproving these contracts, the RCA
must consider the consequences of failing to approve a contract.
4:29:09 PM
MS. DELBRIDGE moved to Section 42.08.330, paraphrasing from the
sectional analysis [original punctuation provided]:
Sec. 42.08.330, Contract carriage certificate,
requires a certificate of public convenience and
necessity (CPCN) for a carrier to construct a pipeline
and to transport gas. The RCA has 180 days to issue a
CPCN once application is made, providing that the
applicant is found fit, willing and able to perform
the services proposed. The RCA may attach conditions
to and amend, suspend or revoke a CPCN. Operating
authority may not be transferred and service may not
be abandoned without RCA approval.
MS. DELBRIDGE elaborated that the CPCN describes the service
area and the scope of operations that are allowed. The RCA must
do a full course of fit, willing, and able if the applicant is
someone other than AGDC. She allowed the 180 days for the RCA
to issue a certificate is a tight timeline, but said it is
reasonable and the point is to not delay a project with overly
long timelines. The RCA may include terms and conditions in the
CPCN if those mutually benefit both the carrier and the public.
If a complaint about the service being provided is filed, the
RCA can modify, suspend, or revoke the CPCN if there is good
cause.
4:31:11 PM
REPRESENTATIVE JOHNSON inquired whether it is automatic approval
should the RCA not act within 180 days.
MS. DELBRIDGE responded she does not see that standard in the
bill language.
REPRESENTATIVE JOHNSON asked [what happens if the RCA does not
act within 180 days].
MS. DELBRIDGE replied she does not know how to answer the
question. In other instances in SSHB 4, she noted, the failure
to approve within a certain timeframe is inherent approval.
4:32:06 PM
REPRESENTATIVE JOHNSON inquired of the sponsor whether this is
something that should be put in the legislation because there is
no motivation for the RCA to do it unless there is automatic
approval.
REPRESENTATIVE HAWKER responded by asking Ms. Delbridge whether
the question is driven by page 45 of the bill, lines 28-29,
which state that "within 180 days after receiving an application
... a contract carriage certificate shall be issued ... if the
[commission] finds ... the applicant is fit, willing, and able
...." Regarding what happens if the RCA does not act within
that timeframe, he asked Ms. Delbridge whether page 46 of the
bill, lines 4-6, provide that if the commission fails to find
the applicant fit, willing, and able, the application must be
denied.
MS. DELBRIDGE confirmed that they do.
4:33:24 PM
REPRESENTATIVE JOHNSON expressed his concern that in a situation
where the RCA did not want to grant a permit, the commission
could stall past 180 days and it would be automatically denied.
He said he would prefer language that grants automatic approval
of the application if the RCA stalls past 180 days because he
wants to build pipelines, not give people reasons not to build
pipelines.
MS. DELBRIDGE answered there are some other instances where [the
sponsors] have incorporated that concept. Speaking for the
sponsors, she said they would like to look at doing so.
4:34:26 PM
MS. DELBRIDGE returned to the sectional analysis, closing her
review of Section 42.08.330 by stating that the rest of this
section is housekeeping. She continued paraphrasing from the
sectional analysis [original punctuation provided]:
Sec. 42.08.340, Filing requirements; public
inspection, requires an instate natural gas pipeline
carrier to file all recourse tariffs, rules,
regulations, terms and conditions pertaining to
service, and all contracts with shippers. Requires
changes in tariff rates/rules and service conditions
to be filed with the RCA.
Sec. 42.08.350, Uniform system of accounts, requires a
carrier regulated under 42.08 to maintain records and
accounts in accordance with the uniform system of
accounts.
Sec. 42.08.360, Expansion; dispute resolution, enables
contracts to provide for expansion, unless an
expansion would violate the terms of the Alaska
Gasline Inducement Act. Requires contracts to include
procedures for resolving disputes.
Sec. 42.08.370, Regulatory cost charge, implements the
standard RCA assessment of a user fee on regulated
entities; includes a cap and directs administration of
the user fee.
Sec. 42.08.380, Effect of chapter on taxes and
royalties, declares that nothing in 42.08 will change
the calculation of production taxes or of royalties
due the state.
4:35:11 PM
MS. DELBRIDGE elaborated that Section 42.08.380 is special to
SSHB 4. She said that just because the RCA and the carriers
have determined a cost of transportation, the bill does not take
away the ability of the Department of Revenue and the Department
of Natural Resources to determine their own reasonable
transportation costs for purposes of a production tax or
royalty.
CO-CHAIR SADDLER surmised Ms. Delbridge to be saying the bill is
not setting a precedent.
4:35:48 PM
REPRESENTATIVE SEATON requested clarification about whether the
pipeline would be subject to property taxes.
MS. DELBRIDGE replied that Section 42.08.380 is strictly about
oil and gas production taxes and royalty valuation of the gas.
She requested the question be held for the appropriate section.
4:36:42 PM
MS. DELBRIDGE continued her review, paraphrasing from the
sectional analysis [original punctuation provided]:
Sec. 42.08.400, Public records, requires RCA records
be available to the public, except as provided by law.
Precedent agreements will be kept confidential. Firm
transportation and other contracts will be public,
except for information that the carrier and the RCA
agree could cause competitive harm.
4:37:17 PM
REPRESENTATIVE SEATON observed there are several places in the
bill regarding public information and that it can be viewed at
the RCA or by pay copying costs. He noted, however, that almost
everything is now submitted electronically. He asked whether
this could be re-structured so that the material is required to
be provided to the public electronically.
MS. DELBRIDGE allowed that is a good point and said she will
consult with the RCA about what its existing regulations are and
whether that is already provided for. If it is not, she said
she will try to find a way to make electronic filing work.
CO-CHAIR SADDLER noted that could be added to the questions for
the RCA when it comes [before the committee].
4:38:20 PM
MS. DELBRIDGE resumed paraphrasing from the sectional analysis
[original punctuation provided]:
Sec. 42.08.410, Investigations, allows the RCA to
investigate matters in 42.08, and maintains the role
of the Department of Law's Regulatory Affairs and
Public Advocacy section.
Sec. 42.08.510, Designation of service agents,
requires an instate natural gas pipeline carrier to
file a named, permanent resident as its agent
(standard RCA provision).
Sec. 42.08.520, Effect of regulations, states that
regulations adopted by the RCA under 42.08 have the
effect of law (standard RCA provision).
Sec. 42.08.530, Judicial review and enforcement, makes
RCA final orders subject to standard RCA judicial
review, except in the circumstances set forth in HB 4,
Section 13, addressing the development, construction
and initial operation of a natural gas pipeline by
AGDC.
Sec. 42.08.540, Joinder of actions, allows appeals to
be joined under applicable court rules (standard RCA
provision).
Sec. 42.08.900, Definitions, defines terms standard to
the RCA (commission, commissioner, record) and
includes HB 4 terms (instate natural gas pipeline,
instate natural gas pipeline carrier).
4:38:56 PM
REPRESENTATIVE TARR requested further elaboration of Section
42.08.530.
MS. DELBRIDGE responded Section 42.08.530 essentially says that
final orders of the RCA are subject to judicial review, except
as provided for under AS 38.35.200, which is the place earlier
in the bill [Section 13] that limits judicial review. If an
appeal is not taken from a final order of the commission within
10 days after an investigation, the commission can apply to the
superior court for enforcement of the order of the commission.
That is essentially a standard RCA provision that lets the
commission have a little bit of an outlet for enforcing its
decisions.
4:39:46 PM
CO-CHAIR SADDLER inquired whether this issue was addressed in
the responses included in the committee packet.
MS. DELBRIDGE answered the packet should have a response from
Legislative Legal Services related to judicial review and
specifically to Representative Tarr's previous question as to
whether the legislature can limit a court's jurisdiction.
CO-CHAIR SADDLER noted that that is a February 12, [2013],
letter from Don Bullock to Representative Hawker.
4:40:40 PM
REPRESENTATIVE SEATON understood the property tax exemption
under Section 34 is only for the duration during construction
and that the private sector would need to pay property taxes
regardless of the ownership structure in a pipeline with AGDC.
MS. DELBRIDGE responded to Representative Seaton by paraphrasing
from the sectional analysis [original punctuation provided]:
Section 34 (property tax exemption) adds a new
subsection to AS 43.56.020, Revenue and Taxation, Oil
and Gas Exploration, Production and Pipeline
Transportation Property Tax, Exemptions, exempting an
AGDC-owned or financed project from state and local
property taxes during construction.
This is one way the state can help an AGDC project
succeed. Waiving property taxes for a period of time
will help keep construction costs down during a highly
risky time in pipeline development. Cost savings
during construction would be reflected in the tariffs
paid for gas shipped on an AGDC line.
4:41:44 PM
MS. DELBRIDGE continued paraphrasing from the sectional analysis
[original punctuation provided]:
Section 35 (repealer) repeals 11 statutes.
· Repeals AS 36.30.850(b)(45) Public Contracts,
State Procurement Code, Application of this
chapter, a prior exemption that applied to an
AHFC pipeline.
· Repeals AS 38.34.030, Public Land, In-State
Natural Gas Pipeline, Joint In-State Gasline
Development Team; 38.34.040, Duties of the
Development Team; 38.34.050, Cooperation and
access to information; and 38.34.060, Conflicts
of interest, all of which were part of [House
Bill] 369 in 2010 and relate to the Joint In-
state Gasline Development Team.
· Repeals AS 41.41.030, Public Resources, Alaska
Natural Gas Development Authority, Term of
office; 41.41.040, Removal and vacancies;
41.41.050, Quorum and voting; 41.41.080, Legal
counsel; 41.41.100, Budget; and 41.41.990(4),
Definitions, all related to the transition of
ANGDA [Alaska Natural Gas Development Authority]
to a marketing role and to an AGDC subsidiary.
4:43:16 PM
Section 36 (repealer) repeals Section 1 of 2002 Ballot
Measure No. 3, the findings of which are no longer
necessary with ANGDA's revised authority.
Section 37 (transition and intent) expresses the
legislative intent that the existing state right-of-
way lease between AGDC and DNR is amended to reflect
the contract carrier covenants in HB 4 (the Alaska
Constitution bars the Legislature from passing laws
that apply retroactively to contracts in place). Also
expresses intent for a smooth transition for AGDC from
its status as a subsidiary of AHFC, to an independent
corporation.
Specifically, this section includes:
· The intent is that this repositioning does not
interfere with, delay or disrupt AGDC's work.
· The intent that the governor should appoint the
new AGDC board within 90 days of the effective
date.
· The AHFC board will remain in place until a new
board is appointed; and will cooperate with the
new board in a smooth transition.
· The intent is that the transition is a change in
placement only, and will not require dissolving
AGDC and creating a new corporation.
· The intent is that AGDC, including employees and
directors, continue in-place while the boards are
transitioning. This is not explicitly stated but
rather is implied.
Section 38 is revisor's instructions
Section 39 sets an immediate effective date.
4:45:45 PM
REPRESENTATIVE SEATON drew attention to page 5, second question
and answer, of the [undated] letter to the co-chairs from
Representative Hawker [answering questions from the 2/4/13 and
2/6/13 committee meetings]. He recalled committee discussion
about timelines for release of confidential information and
noted the answer in the letter states that the bill "does not
restrict the confidentiality by time, this information may be of
public benefit once a pipeline is operational." He said what
was being looked for with the question was having timelines for
release of information that no longer needs to be held
confidential. He requested that such an answer be prepared and
brought to the committee for incorporation into the bill.
4:47:13 PM
CO-CHAIR SADDLER requested Representative Seaton to re-state
what information he is requesting.
REPRESENTATIVE SEATON read the first sentence in Representative
Hawker's answer: "HB 4 allows for certain information to be
held confidential, and does not set time limits for that
protection." However, Representative Seaton continued, the
question posed was whether a provision can be put into the bill
for releasing confidential information once it no longer needs
to be held confidential. For example, release of that
confidential information after the pipeline becomes operational
or at certain other time periods identified by AGDC.
4:48:53 PM
The committee took a brief at-ease.
4:49:05 PM
FRANK RICHARDS, Manager, Pipeline Engineering & Government
Affairs, Alaska Gasline Development Corporate (AGDC), Alaska
Housing Finance Corporation (AHFC), Department of Revenue (DOR),
, at the request of Co-Chair Saddler, responded to
Representative Seaton's question. He explained that a variety
of items would be deemed confidential, such as information in
commercial agreements, information held by third party or other
state entities that has been deemed confidential and that AGDC
would gain access to through the bill's provisions, and
information that AGDC acquires through its own work or has
contracted for that will be held confidential. As identified in
the response [on page 5], commercial terms in precedent
agreements, for example, would be released after going through
the RCA process to the extent that the individual shippers did
not hold commercial interest or wanted that to be held
confidential. A specific listing and a timeframe for when that
information will be released would be hard to ascertain at this
time. Currently, AGDC holds information that it acquired from
the predecessor of the project, ENSTAR, and that information is
held confidential by AGDC as it works this process forward until
the point of actually constructing and completing the process.
Then it will have been used by AGDC as a public entity and it
would then have gone into the public realm. When accessing
information held by another department, AGDC is unable to
control the release of that information. Mr. Richards offered
to address specific information that Representative Seaton would
like and provide a timeframe that AGDC thinks it might be able
to release it.
4:51:09 PM
REPRESENTATIVE SEATON noted that a lot of information on this
project is confidential and said he thinks the public's
confidence in the process becomes much greater if it is known
that information not required to be held confidential will be
released at some point, such as when the pipeline becomes
operational. He agreed to discuss this issue further to see if
specific areas can be identified.
MR. RICHARDS said he would be glad to talk with Representative
Seaton and with AGDC's commercial manager about which specific
commercial issues would likely be held confidential through the
precedent agreements. He added that AGDC will also be acquiring
information as a state entity that will be held as confidential
up to a certain point and, once released, will be a benefit to
the citizens of the state.
4:53:01 PM
CO-CHAIR SADDLER held over SSHB 4, saying it will be taken up
again on 3/15/13. He then recessed the meeting to a call of the
chair.
7:49:24 PM
CO-CHAIR FEIGE reconvened the House Resources Standing
Committee. Representatives Seaton, P. Wilson, Johnson, Saddler,
and Feige were present at the call back to order.
Representatives Tarr and Tuck arrived as the meeting was in
progress.
HB 72-OIL AND GAS PRODUCTION TAX
7:49:32 PM
MR. PULLIAM continued his review of projected cash generation
per barrel from ongoing production under ACES in comparison to
other jurisdictions [slide 32]. He explained the graph is an
average across all of the North Slope and is not reflective of
an incremental investment. Cash is generated from all ongoing
activity and the graph compares it with the cash that is
available from other locations, and it can be seen on the graph
that the effect of progressivity keeps the cash generation lower
in Alaska than in other jurisdictions.
7:50:27 PM
CO-CHAIR FEIGE inquired why the line depicting Canada is stair-
stepped while the lines depicting the other areas are smooth.
MR. PULLIAM replied Canada has different brackets in the way its
very complex system is applied.
7:50:52 PM
REPRESENTATIVE SEATON noted Norway has a 78 percent tax and a 28
percent [indisc.]. Observing from the graph that at $100 per
barrel the cash margin for Norway is $40, he concluded this
depicts a tax rate of 60 [percent].
MR. PULLIAM responded no, there is still that [78 percent] tax
rate at least in the initial period. He explained Norway has
some uplifts and some recovery of costs that add to the
producer's margin in the first number of years of production, so
the complexity of Norway's overall system gives the look seen on
the graph. That higher margin is a function of the uplifts and
the recovery of that initial investment against the different
taxes in Norway.
7:52:12 PM
REPRESENTATIVE SEATON related that when [Alaska legislators] met
with Norway's oil finance minister, the minister said the uplift
was to partially mimic or get to where Alaska is with allowing
deductibility in the year. Given that Alaska's and Norway's tax
rates are very similar, he asked why the graph depicts such a
huge discrepancy between the two areas. He further asked
whether the graph depicts the initial years for Norway rather
than the ongoing.
MR. PULLIAM answered the graph is for the initial years in and a
lower margin will probably be seen later in the lifecycle in
Norway.
7:53:05 PM
MR. PULLIAM resumed his presentation, specifying it is important
to think about investment opportunities as well as industry's
perception of Alaska's system [slide 33]. He related that
reports published about the different systems around the world
talk about Alaska's tax rate being between 25 and 75 percent,
which is an accurate description. For example, in 2011 the
consulting firm IHS CERA did a report for the U.S. Department of
Interior. [Page 225] of that report describes Alaska's fiscal
system and states Alaska's profit tax is between 25 and 75
percent. People looking at this kind of report do not scratch
down through the surface to figure out what rate applies, they
see the report and that is their initial perception of the
state. This is consistent with what Commissioner Sullivan is
reporting about his talks with companies interested in Alaska -
their impression right off the bat is that Alaska's tax rates go
up pretty high.
7:55:09 PM
MR. PULLIAM noted the 2011 IHS CERA report also ranked fiscal
systems throughout the world to help the U.S. Department of
Interior gauge the competitiveness of the federal system [slide
34]. Alaska's fiscal system was ranked second to the highest,
which is not a good place because from an investor's perspective
the lower the ranking the better. While he does not necessarily
agree with the complex way that this rating system was done, he
said it is published and is what people are seeing when looking
at participating in Alaska. Responding to Co-Chair Saddler, he
said the parameters used in this ranking include government
take, profitability index (PI), internal rate of return (IRR),
and progressivity/regressivity. He explained the method used in
this ranking gives a poorer score to systems that are highly
progressive or regressive, so relatively neutral systems get
better scores from an investor's standpoint. Another parameter
used is revenue risk, which has to do with the timing of when
the sovereign receives its money. Also used as a parameter is
the stability of the system over time, which considers the types
of change that have occurred in the fiscal system, as well as
the applicability, degree, and frequency of change. There is
subjectiveness to the way the ranking is done, but this is what
people are looking at and from an investor's standpoint Alaska
is at the tougher end of the spectrum. This ranking is
consistent with what is seen in government take statistics
generally in which Alaska has some of the higher numbers in
government take.
7:58:11 PM
REPRESENTATIVE TUCK noted chapter 4 of the book, [The Taxation
of Petroleum and Minerals: Principles, Problems and Practice],
discusses that the effectiveness of a tax regime cannot be
looked at by the tax rates alone. He therefore asked what else
legislators should be considering with the fiscal system of
Alaska when comparing slides 33 and 34.
MR. PULLIAM replied the chart [on page 34] looks at a lot of
different categories. The take is a measure of the tax rate.
The type looks at whether it is progressive or regressive
system. The PI and the IRR measure whether the system is
designed in a way that provides acceptable profitability for the
investor. The four categories of [type, applicability, degree,
and frequency of change] measure how stable a system is and how
responsive it is. Stability and competitiveness are important
components for investors in thinking about a fiscal system. So,
yes, the tax rate is important, as are the competitiveness of
the government take and the degree to which the system is going
to stay in place and not be subject to change. A frequently
changing system makes it difficult to plan, so the risk of the
investment is greater. People want to see a system that is
durable and will last for as long as is reasonable.
Circumstances in the world change and that necessitates at times
that systems change. Investors appreciate that systems are
dynamic in some ways. A key factor is that investors can be
confident that if changes occur, the system will remain
competitive and attractive relative to what the investor can be
doing elsewhere.
8:01:28 PM
MR. PULLIAM next addressed the administration's proposed changes
in HB 72 [slide 36]. He outlined key aspects of the proposal,
saying it would: establish a 25 percent flat [net tax] rate,
which is the current base rate, and eliminate progressivity;
eliminate capital credit and state purchase of losses; establish
a 20 percent gross revenue exclusion (GRE) to incent production
of new oil; allow producers to recover losses from the
development phase by carrying them forward to when production
occurs and a tax obligation is incurred to count them against;
extend the new entrant or small producer credit through 2022;
and not change the tax structure outside the North Slope.
8:03:05 PM
MR. PULLIAM reviewed benefits of HB 72, specifying it would
provide a balance between the state and the producers [slide
37]. Reduction of tax rates at higher prices would be balanced
with elimination of credits. The state would continue to
receive the largest percentage of oil production revenues at any
price - larger than the federal share and larger than the
producer share. The bill would provide tax relief and higher
margins in a sustainable price range, which is about $80 to $140
per barrel. He noted that prices above and below those levels
would be hard to sustain on an ongoing basis, but that does not
mean such prices might not occur from time to time. Another
benefit of the bill is that it would greatly simplify Alaska's
tax system and provide better clarity for planning. It will be
easier to factor in how the system is going to impact
investments, will eliminate the high marginal tax rate, and will
eliminate the uncertainty of what a producer's tax will be at
different prices. It eliminates incentive for producers to
"gold plate" by spending money less efficiently at high prices
when the state's share of spending rises to almost one for one.
8:05:58 PM
MR. PULLIAM, continuing his review of the bill's benefits, said
it maintains an alignment between the state and the producers'
economics by staying with a net tax system. The gross revenue
exclusion (GRE) provides a way to lower the effective tax rate
for new development without the treasury having to provide
significant funds upfront to do the same. The GRE substitutes
economically for those credits that the state provides because
it allows the producers to keep a greater share of what they
produce when it actually comes on line. Finally, the bill will
send a very positive message to potential investors as well as
to those already here. It will encourage broader participation
on the North Slope, which is something the state needs. The
bill will move the economics of new participants closer to what
the incumbents enjoy.
8:07:47 PM
REPRESENTATIVE SEATON, in regard to maintaining the incentives,
recounted that when the legislature was developing the
production profits tax (PPT) and Alaska's Clear and Equitable
Share (ACES), the companies testified that tying investment
credits to production would not incentivize them because of the
long lead times; that it was most appropriate to tie it to
investment because those investments are made up front and are a
known quantity. He inquired whether industry told the
legislature wrong, given that now the proposal is to tie the
credits to production.
MR. PULLIAM responded that is a good recollection of the history
and said he can understand from the beneficiary's viewpoint why
the beneficiary would rather have that credit guaranteed by
tying it to the outlay of capital as opposed to performance-
based production. However, he continued, what is being talked
about here is eliminating the credit itself and the need to
provide that outlay, but rather letting the producer keep a
greater portion of the profits that come from the production
itself. Some people say that the credits do not offset the
increased take of progressivity at prices of $90 per barrel and
higher. Progressivity bites more than the credit provides from
the producers' standpoint. Under HB 72, eliminating the credit
and also eliminating the progressivity maintains the appropriate
economic incentives, and inclusion of the GRE enhances those
incentives without having to provide that credit up front.
8:11:17 PM
REPRESENTATIVE SEATON recalled testimony before the committee
about new oil where the companies stated that if expenditures
were made in a new field that turned out to be dry there would
be no help from the state and so no security. The testimony was
that to incentivize development it was much more appropriate to
have it tied to investment. Now it is being said they will
invest, when before the companies said it would not stimulate
investment.
MR. PULLIAM answered he does not think the context of what was
put forward to the companies before was whether they would
rather have the credits and pay a higher tax rate or not have
credits and pay a lower tax rate. What is being talked about
here, he said, is a credit versus a higher tax rate tradeoff.
The system proposed under HB 72 maintains appropriate economics
for the incumbents to continue and expand investment by lowering
the tax rate even though the credit is being removed. Also, it
enhances those economics particularly for new participants even
though the state is not going to be buying those credits from
them up front, because it removes progressivity and offers them
the GRE and allows an uplift on their initial outlays for
development. All of those things factor in to enhancing the
investment decision.
8:13:50 PM
REPRESENTATIVE TARR said a criticism of the credits is that they
are being applied to maintenance costs and things not related to
production. However, [the state] needs the companies to keep
making those maintenance investments for some period of time
until the new production comes on. So, it appears there is a
timing issue where there is a disincentive now for some of those
costs because the companies would not have the credits. She
requested Mr. Pulliam to speak to how other jurisdictions deal
with credits and whether they are up front.
MR. PULLIAM replied that from his review, where those types of
things are offered they are typically taken against production
and taxable income. He surmised that imbedded in the question
is a concern that removing the credits removes the appropriate
incentives to continue with necessary maintenance.
8:15:10 PM
REPRESENTATIVE TARR agreed that is correct in part, but said it
seems to her that the timing is not totally in sync with ongoing
costs that might be happening in the near term related to what
happens when new production comes on.
MR. PULLIAM responded part of any business endeavor involves
making an investment up front in hopes of making a profit on
that investment, and the oil industry is very typical that way.
The companies make an investment up front - they explore, shoot
seismic, drill exploratory wells, and then develop. The largest
part of the expense is in the development and then after that
the company gets production. The industry is very well
accustomed to footing the bill for that development in
anticipation of receiving a profit on it down the road. When
Alaska went to the PPT system, and more so when it went to ACES,
the state said it was going to provide companies a bigger
incentive to make that upfront investment by giving them this
credit, but would recover that by taking more of the profit down
the road. The state tried to tilt the scale to accelerate that
investment, thinking that by providing more up front, it would
be sufficient for industry to forego a bigger piece of the
revenue stream down the road; however, it has not worked. The
proposed legislation, he continued, removes those upfront
credits and significantly reduces the amount of the
progressivity down the road when the production actually comes
on. This would put Alaska to being more like what the companies
experience in the rest of the world, which is the norm and is an
environment in which the companies know how to play.
8:17:47 PM
REPRESENTATIVE TUCK stated that at high oil prices more capital
is available for producers to buy down their tax rates by making
sure they invest in Alaska. It does not help them investing it
outside of Alaska, but it greatly benefits them here in Alaska.
There is 17 percent more investment from one year to the next,
and by adding that 17 percent, industry can get 63-95 percent
more tax break [slide 23]. He said it seems that reducing the
tax rates at high prices and then balancing that with
eliminating the credits is doing just the opposite - the state
is giving more profit back, but there is no guarantee that that
is going to be spent in Alaska, especially when those tax
credits are eliminated. [For new participants] the state has a
10-year period in which those tax credits can be carried. The
span between investment and start of production is much longer
in Alaska than elsewhere due to the seasonal limitations on when
work can be done. Giving upfront credits frees cash for the
company to invest next year. He asked whether the problem [the
administration] has with this provision of ACES is that it is
hard to know whether [the credits] will lead to production. He
further asked why the state would not want to have more
investment in Alaska and let industry determine what is best to
get oil down the line, given that is what industry wants to do.
8:20:02 PM
MR. PULLIAM answered industry wants to make money and getting
oil down the line is industry's way to make money, but only if
it can keep a competitive portion of what it puts down the line.
He agreed that moving the tax rate down and eliminating the
credits is opposite of where the state is now. Providing those
big credits and having the progressivity means that as long as a
company brings that money back to Alaska, then it is a good
deal. But if the company decides not to, then it is not a good
deal. If you were an investor looking at where to invest, would
you want to invest someplace where you have the freedom to
respond to oil and market opportunities and reinvest your profit
where it makes sense? Or, would you rather spend your money in
a place that says it will let you earn those profits, but only
if you keep them here? Alaska's current system provides for
bringing the funds back to Alaska, but that does not produce the
same quality of profit that can be produced elsewhere. That is
like owing money to someone and asking whether that person would
like cash or a gift certificate. Which would you rather have,
which is more valuable? The norm elsewhere is you get the cash.
Investors would find it much more valuable and would find Alaska
much more attractive as an investment opportunity if they have
the freedom to use their profits in the best way possible.
While there would be no guarantees that they would reinvest in
Alaska, the state can provide a competitive system that allows
investors to then respond to normal market incentives to put
that money back here. If investors can earn in Alaska what they
can earn elsewhere, the state ought to see it put back here.
Alaska is allowing them to earn essentially gift certificates,
and giving them something they can get elsewhere. He said he
thinks that is part of the reason why Alaska is not seeing the
behavior it thought it would see under ACES.
8:23:19 PM
REPRESENTATIVE TUCK said he is having a hard time with bringing
down Alaska's system to the lowest common denominator and hoping
to see investments in Alaska. All activity on the North Slope
leads to production at some time because everybody wants to be
profitable. It almost makes more sense that getting companies
to produce and then reducing will guarantee that money comes
into Alaska and is reinvested in Alaska, he argued. During the
days of the economic limit factor (ELF), Alaska's fields, some
of the largest fields in North America, still declined and did
not flatten out. The declines are natural and Prudhoe Bay has
been [producing] for 35 years. He asked how long the North Sea
has been [producing].
MR. PULLIAM replied they were developed about the same time.
8:24:59 PM
REPRESENTATIVE TUCK stated he does not see the North Sea curving
up any differently than is Alaska.
MR. PULLIAM responded the United Kingdom (UK) has recently made
significant changes to its system to try to address that. The
UK and other places got caught up with trying to increase taxes
as those natural declines were occurring and prices went up.
They found that it continued to scare off investment and, unlike
in many other places, as prices have come up the UK has not
gotten the kind of response it was looking for. North Sea
production is down just like it is in Alaska and the UK has
taken measure to address that. Recognizing that not everyone
will agree with him, he said he thinks it is a fundamental
matter of economics that incenting activity requires being
competitive with the other opportunities that are out there.
Also, he continued, a system that does not attach strings to the
profit earned is better quality and more attractive. Those are
the appropriate kinds of incentives to provide to profit-seeking
companies to make investments. When those freedoms are not
allowed, there is not the same quality of opportunity that
exists elsewhere and a natural result of that is that the
desired kind of activity will not be seen.
8:27:13 PM
REPRESENTATIVE SEATON disagreed with Mr. Pulliam's earlier
statement that the reaction under ACES was not as anticipated or
was not very good. He pointed out that a number of new
companies, such as "Repsol, Brooks Range, ENI, Stat Oil, Loyal,
Great Bear, Savant," are now on the North Slope that were not
there before [ACES] and just about half of the total investment
credits are in that investment. He allowed that tweaks could be
made, but asked how it can be said that ACES has not had the
desired effect given that activity and that many new companies
have come into Alaska.
MR. PULLIAM maintained a great number of those companies were in
Alaska before enactment of ACES. He said Pioneer is a company
that has gone through ELF, PPT, and ACES and is still here.
REPRESENTATIVE SEATON noted he did not mention Pioneer.
MR. PULLIAM continued, saying ENI bought its interest in
Nikaitchuq before ACES was in place. Repsol was courted and
attracted to Alaska by Armstrong, the same folks that attracted
ENI. He said he thinks the interest is due to the resource and
given where prices have gone there would have been more interest
had there been a more simple system without the high take that
Alaska has.
8:29:28 PM
REPRESENTATIVE TARR said the 7-10 year timeframe that has been
discussed as the amount of time it takes to bring on production
is affirmed in HB 72 because the proposed certificates are good
for 10 years. She therefore asked whether the situation is
being assessed prematurely because there has not yet been the
typical timeframe to bring on new production.
MR. PULLIAM answered that is certainly something to keep in
mind, but said he does not think it premature to look at the
effects five years into ACES and six years since PPT passage.
As indicated by the slides earlier in his presentation,
production was looked at along with other measures of activity,
such as drilling and investment, and those things have not
increased under ACES as they have elsewhere in the world. As
prices have gone up, those activity levels have gone up
elsewhere. Looking at all of that in combination is
instructive. Given the kind of price increase and what is seen
elsewhere, it would be expected to have a bigger increase in
Alaska and the question is why not. He charged that ACES has
been an impediment to more activity and to putting Alaska in a
more robust situation.
8:31:31 PM
REPRESENTATIVE P. WILSON cautioned members about going under the
premise that ACES was totally planned out and that it planned
for certain things to happen. She pointed out that amendments
were made on the floor with no clue as to how they would
interact with each other, so there is no way to look at ACES and
say there was a plan.
MR. PULLIAM replied he was less involved with the ACES debate
than he was with PPT. The PPT was a major change from the prior
system and a lot of thought went into it, he said. It was new
ground that was being charted and a lot of analysis and
consideration was paid to what was an appropriate tax rate and
what kind of progressivity could be put in place so that if
prices went up substantially the take would go up. While he was
less involved with ACES, where he was involved he was telling
people to be very careful about moving up that progressivity
piece. A lot of the reason for moving it was based on some
analysis strictly involving internal rate of return. While
internal rate of return is a measure to use, it is certainly not
a deciding measure and one that he would be very cautious in
using on its own. He recalled that the move from 0.25 percent
progressivity to 0.4 percent came very quickly at the end of
session and the ramifications of the 0.4 were not as well
considered, particularly given the kind of changes in price.
Back then people did not think high prices of $100 per barrel
could happen and that if they did it would not be sustained for
more than a month every three or four years, and therefore the
high progressivity would not do much damage. However, it is a
different situation if that is where the price is on a regular
basis. He offered his agreement with much of Representative P.
Wilson's characterization.
8:35:29 PM
REPRESENTATIVE SEATON pointed out that credits were adopted
before PPT and ACES, and then noted that nothing is being said
about the balancing act that took place when PPT and ACES were
being discussed. Under the previous gross tax, a company paid
tax whether it made or lost money. The companies asked for
protection on the downside, but he is not seeing any balance
with the downside protection coming back in with taking away the
progressivity. The two elements of balance - giving downside
protection while taking more of the upside - are not being
looked at. He requested Mr. Pulliam to discuss this.
MR. PULLIAM addressed the request by moving to slide 38 in his
presentation regarding the average government take under ACES
versus HB 72 for all existing North Slope producers for fiscal
years 2015-2019. He explained that under ACES the percentage of
government take rises [as the price per barrel rises]: at just
above $80 per barrel, government take reaches [approximately 64
percent], which is the take also envisioned under HB 72 at that
price; the take continues upward until reaching 75 percent at
higher prices [of $150 and above]. Under HB 72, government
take at [$70 per barrel] is actually greater [about 66 percent]
than under ACES [about 62 percent], then it [decreases] and
flattens out as prices increase [about 62 percent take at $160
per barrel]. So, HB 72 actually has a little more downside
protection than there currently is under ACES.
8:38:31 PM
MR. PULLIAM next compared the average government take at $100
per barrel for jurisdictions throughout the world for fiscal
years 2015-2019 (slide 39 prepared by PFC Energy). He said he
used PFC's data from slide 39 to develop the graph on slide 40
[depicting average government take for all existing producers in
Alaska under ACES and under HB 72, and the average of government
take for the other jurisdictions]. The average government take
for the other jurisdictions stays at about 65 percent [at prices
ranging from $70 to $160 per barrel]. Looking at only the major
OECD jurisdictions, the average government take starts at about
65 percent [at $70 per barrel] and falls to about 63 percent as
prices go up [to $160 per barrel]. He said this decline
reflects a slight regressivity due mostly to the effect of the
gross-based royalty and tax system used in the Lower 48 which
gives a somewhat regressive take. [Under HB 72, the average
government take begins at about 65 percent at $70 per barrel,
falling to about 62 percent at $160 per barrel; under ACES, the
average government take begins at about 62 percent at $70,
rising to about 75 percent at $160.]
8:40:05 PM
REPRESENTATIVE SEATON inquired whether the aforementioned graphs
include downside protection in credits, as he does not see any
change in HB 72 as far as changing the production tax downside
protection.
MR. PULLIAM responded yes, credits are factored into this
analysis as they are part of the government take. Under ACES
the state provides a tax credit of 20 percent even when prices
go down and that is a big part of what is being seen.
REPRESENTATIVE SEATON surmised that [HB 72] does not change the
downside protection in the production tax, but just takes away
the upside.
MR. PULLIAM understood current law has a floor of 4 percent on
the gross and said he does not think the proposal changes that.
The base level of 25 percent is maintained [in HB 72], so at low
prices the tax is 25 percent without credits, which provides a
higher take than currently under ACES.
8:41:55 PM
REPRESENTATIVE SEATON observed that slide 40 is for all existing
producers and asked whether Mr. Pulliam will be addressing the
effect of the GRE when it becomes a large percentage of the oil.
MR. PULLIAM answered he will have analysis later in his
presentation that looks at how the GRE would play out. He
pointed out that the gross revenue exclusion does apply here
because it is a forecast of fiscal years 2015-2019 and some of
the production during those years will qualify for the GRE.
REPRESENTATIVE SEATON asked which production is included.
MR. PULLIAM replied Nikaitchuq and Oooguruk would qualify for
the GRE. In further response, he said those two fields are on
right now.
CO-CHAIR FEIGE noted the unit was formed after January 1, 2004.
8:43:13 PM
REPRESENTATIVE TARR observed slide 40 only goes down to a price
of $70 and inquired whether Mr. Pulliam thinks prices will not
go down below that. Perhaps the prices should go down lower,
she suggested, in the interest of being cautious given that
during the ACES debate no one predicted that oil prices would go
so high.
MR. PULLIAM agreed to provide an expansion of the graph, but
cautioned against putting too much weight on it because the
challenge of $60 per barrel is whether it is a sustainable
number. That price would be uneconomic, he explained, and
therefore a lot of production that is occurring now would just
fall off. That is not to say there would be no time periods in
which the price could fall below $70, he continued, because in
2009 prices dropped $100 per barrel in the course of 6 months,
but they did not stay there very long.
8:45:00 PM
MR. PULLIAM resumed his presentation, moving to slide 41. He
pointed out that under [HB 72], cash generation [from ongoing
North Slope production during fiscal years 2017-2021] moves up
[as prices increase from $70 to $160 per barrel]. He said this
cash generation is in the range seen elsewhere in the OECD, a
positive for the investment community.
MR. PULLIAM next posed a hypothetical scenario of a 50-million-
barrel field of light conventional oil developed by a new
participant in Alaska [slide 42]. He compared the annual state
revenues and producer cash flows of ACES with HB 72 for this
hypothetical field at a West Coast ANS price of $100 per barrel.
He said he used this field size because it is the kind of field
that is recently being discovered and which is expected to be
seen more often than a large field. Under ACES, the NPV is $192
million and the cash flow for the producer over the course of
the project would be [$981 million]. Under HB 72, the NPV is
$309 million and the producer's cash flow would increase to
[nearly $1.6 billion]. For state revenues, there would not be
the large outflow under HB 72 like there is under ACES during
the development period. This is because under HB 72 the state
would not be buying back the credits and the NOLs; however, the
state would be allowing recovery of those losses when production
starts. As a result, the NPV of state revenues would be reduced
[from an NPV of $666 million and total revenues of $2.5 billion
under ACES to an NPV of $486 million and total revenues of $1.6
billion under HB 72].
8:47:54 PM
MR. PULLIAM then posed this same hypothetical scenario for an
incumbent participant [slide 43]. For producer cash flows under
ACES, an incumbent's NPV would be $307 million and under HB 72
it would be $310. For state revenues, the NPV would also be
pretty comparable [$489 million under ACES, $485 under HB 72].
What these two graphs show is that HB 72 would have the effect
of enhancing the new participant's economics and bringing them
in line with what an incumbent already enjoys. In response to
Co-Chair Feige, he explained that $0 in the Y axis represents
when the first spending starts to occur, so the decision to
proceed to develop would have been made shortly before that and
some production would start in year four.
8:49:22 PM
MR. PULLIAM summarized investment metrics for a new participant
in a hypothetical light conventional oil development in Alaska
under ACES and under HB 72 versus the other benchmark areas
[slide 44]. At a [West Coast ANS] price of $100 per barrel, the
NPV under ACES would be $3.85 a barrel. Under HB 72 the NPV
rises to $6.18 with the GRE, which a new participant should
qualify for and which compares favorably with the Lower 48 and
the UK [$6.75 in Eagle Ford, $4.29 in Bakken, $6.04 post-1993 in
UK, $8.25 post-1993 with Brownfield Allowance in UK]. The other
metrics [under HB 72] are improved as well; for example, with
the GRE the government take falls [to 61.1 percent] and without
the GRE it is [64.7 percent], both of which are significantly
lower than is currently the case under ACES [75.8 percent],
making it attractive relative to what exists elsewhere.
8:51:46 PM
REPRESENTATIVE SEATON noted the government take, both with and
without the GRE [under HB 72], is lower than the Eagle Ford,
Bakken, and other provinces.
MR. PULLIAM responded it is lower than some provinces and higher
than others. The average for all OECD countries is around 63
percent and the average for all jurisdictions is 65 percent, so
Alaska would be a bit better than that, which is a good thing.
8:52:35 PM
MR. PULLIAM continued his presentation, looking at the same
hypothetical scenario but this time from the standpoint of an
incumbent [slide 45]. At $100 per barrel, the NPV under ACES is
$6.14 compared to [$3.85] for new participants. He reiterated
that [HB 72] brings up the economics for new participants to
where an incumbent is. For an incumbent under HB 72, the NPV
[of $6.20] is comparable to ACES and at a higher price [$120]
the NPV is better than ACES [$9.69 versus $8.82]. This compares
favorably to other development opportunities in the rest of the
world. Thus, it can be seen that the cash margins are enhanced
quite a bit under HB 72 relative to ACES. Government take under
HB 72 is a little different [62.6 percent at $100/barrel] for an
incumbent than for a new producer since new producers have a tax
credit that the incumbent does not have.
8:54:11 PM
REPRESENTATIVE TARR, observing that the five-year predictions
are for fiscal years 2017-2021, inquired whether it would be
more appropriate to be looking forward for the coming years in a
closer timeframe given that HB 72 would take effect immediately.
MR. PULLIAM answered he looked at the period of 2017-2021 for
this hypothetical development because the field was developed
out in that [earlier] time period and the producer is starting
to earn revenues during the 2017 period. It should not look
different if a different five-year period is used looking at
that same development cycle.
8:54:59 PM
REPRESENTATIVE TARR said it seems like the heavy investment cost
that comes in those early years would affect this.
MR. PULLIAM specified that what is being looked at is once
production gets on line because margins are not generated until
production gets on line. A hypothetical development started
this next year would be on line and producing in about 2017, so
that is the reason for using the time period of 2017-2021. A
development started before now and just now beginning production
under this system should show the same picture. In further
response, he confirmed it would show the same picture even
though the elimination of credits.
8:55:53 PM
REPRESENTATIVE TUCK surmised that of the jurisdictions listed on
slide 39, the North Sea is close to what Alaska has in Prudhoe
Bay. He asked whether any of the other jurisdictions are
similar to Prudhoe Bay or the North Sea, and whether any of
those have reversed their decline. He said he does not think
the North Sea's decline has yet been reversed.
MR. PULLIAM responded he knows some reversal has occurred in the
North Sea. The emphasis, though, is that there has not been an
aggregate turnaround. Turning around a basin is a different
issue than turning around a field, he stressed. Fields have a
natural decline and making that decline go as slowly as possible
is the goal. Prudhoe Bay has produced much longer than anybody
ever expected; the decline has been extended and extended. It
is one of the most prolific fields in the history of the world.
He said he does not think the view is that it can be turned
around by adding a significant amount of gas handling capacity.
The decline can be stemmed by doing certain things and is
something people would like to see happen. But the decline
overall is really a basin-wide thing and to stem that, oil must
be brought in from other areas. As far as pointing to a field,
he said there have certainly been some, such as Apache doing
that in a North Sea field. But, in general, the effort there is
to incent oil production in and around existing fields and find
new oil. He said his experience is that turnaround is more
basin-wide or area-wide than it is field-wide.
8:59:24 PM
MR. PULLIAM concluded his presentation by directing attention to
the appendix [slides 46-62], which provides more detailed
comparisons of Alaska activity to places elsewhere in the world.
He pointed out that many of the investment metrics he reviewed
in tabular form are in chart and pictorial form in the appendix.
9:00:48 PM
REPRESENTATIVE SEATON recalled an earlier discussion with the
Department of Natural Resources commissioner about the Forties
Field, the only example of a turnaround field. A legacy
producer that was been in decline for years sold the Forties
Field; so, the only turnaround was one that came due to a change
in the culture of the operating company. It has been stated in
testimony, he related, that the companies' strategic view of
Alaska is to generate income for other investments around the
world. Therefore, he asked, how does going from ACES to [HB 72]
function to actually change the decision making culture that has
been ongoing on the North Slope since pre-PPT and is continuing
in the legacy fields.
MR. PULLIAM, rather than talking about a culture, replied that
these companies are in the business of making money and the way
they make money is by producing oil. To the extent that [HB 72]
is an attractive, profitable proposition, the companies can be
expected to respond to the incentives. The companies should
respond if Alaska puts the right incentives in front of them,
the opportunity to make money, to make a competitive return on
their investment similar to what they are getting elsewhere.
Some of the more mature basins do attract other companies that
are not the companies that developed those basins. That is what
is wanted in Alaska. A system can be provided that is as
welcoming to those companies as possible. The changes being
talked about in HB 72 do exactly that.
9:04:22 PM
MR. PULLIAM, continuing his response to Representative Seaton,
said examples similar to what was done in the Forties Field can
be found in California where Occidental bought out the interests
of companies that had developed fields and that those companies
had decided no longer fit with their strategic interest. Alaska
cannot really do anything to determine who the producer is or is
not. But Alaska can try to make it attractive for them to
operate here and do so in a way that makes the opportunity in
Alaska competitive with what they have elsewhere, whether it is
a new or incumbent producer. Culture notwithstanding, it can be
expected that rational investors would respond to that. There
is no reason to believe that these folks are not rational. They
may not always do things that Alaska likes and they may do them
in a different time frame, but they are rational investors and
if incentives are put in front of them to earn in Alaska what
they can elsewhere, then [policy makers] have done their job.
And if they get down the road and decide an asset no longer fits
with their strategic desire and they want to sell out to a
smaller company, then Alaska would have the right system for
them to operate in.
9:06:36 PM
REPRESENTATIVE TUCK agreed with the statement that companies are
rational investors; they want to make money. He said Alaska's
aggressive tax credit system is one of the best in the world and
he is led to believe the companies are making rational decisions
in investments on the North Slope. More investments are
happening now than under prior tax regimes ...
MR. PULLIAM interjected, stating he disagreed. Alaska has seen
a higher level of investment, he said, but when the worldwide
increase in prices is controlled for, Alaska does not have a
significantly higher level of investment. Investment in Alaska
has lagged relative to that elsewhere in the world. Yes, it is
higher than it was in, say, 2003, but it is higher everywhere
and the increase is much, much higher elsewhere than it is in
Alaska. So, he sees that as a slowdown and that Alaska has not
kept pace. It has become more expensive to operate in this
higher-price world, he continued, so just the same things a
company was doing back in 2003 cost more today and because of
that, more has to be spent to maintain the same kind of
activity.
9:08:10 PM
REPRESENTATIVE TUCK pointed out that more companies are now in
Alaska and said more may have sprung up around the world because
the profits are so high. He understood that existing producers
will not put themselves out of business any quicker than they
have to, so they are going to maximize the price that they can
per drop of oil. It may not be in their best interest to just
produce, produce, produce, especially if they can maintain those
prices high - the basic laws of supply and demand. He noted
that tankers are coming back to Valdez with their hulls still
full because the refining capacity is full. What is in the best
interest of the companies may be against the best interests of
what Alaska wants to see. So, there is this balance of trying
to get to that million dollar barrel a day that the governor has
put forth. It would be nice to have more concrete ways of
getting there, but it goes back to making sure the investments
stay in Alaska as best as possible.
MR. PULLIAM responded that, from his perspective, he would say
it a little differently: It is not to make sure the investments
stay in Alaska, it is to make sure Alaska attracts the
investments. What is wanted is for the people who are here now
to have more incentive to invest here and for the people who are
not here to have incentive to invest here. He said he thinks
Alaska would do a better job with that under HB 72 than the
current system. While there are more companies on the North
Slope, what is wanted is even more. The proposed changes would
move Alaska in that direction in a real positive way.
9:10:56 PM
CO-CHAIR FEIGE offered a correction regarding the tankers,
saying the reason they came back to Valdez with oil in their
holds was because the storage facilities at the refineries could
not take it. Part of that was a capacity problem due to two
fires, a major one being at Cherry Point, Washington, that shut
down the refinery from February-June 2012. Another was a
maintenance issue at the refinery in Oakland, California. The
tankers had to return, not necessarily because the refineries
could not take their oil, but because Alaska needed those
tankers back in Valdez to take oil out of the tanks because the
Trans-Alaska Pipeline System (TAPS) was approaching 90 percent
fill. Had those tankers not come back, wells would have had to
be shut in, which would have adversely affected the state's
production of oil.
9:12:14 PM
CO-CHAIR FEIGE understood Mr. Pulliam to be saying that while
ACES incentivizes spending, there is nothing in ACES that
ensures that that spending results in production. Even though
there is no guarantee in ACES, that guarantee has led to a lot
of new pipes and many well maintained facilities, but ACES has
not led to production, and production is what the State of
Alaska makes its money on in the future. He said he thinks Mr.
Pulliam has highlighted very nicely that credits must be tied
much more closely to production and, hence, future tax revenue
for the State of Alaska.
9:13:10 PM
REPRESENTATIVE SEATON requested runs be made for when Alaska
reaches 50 percent new oil because if the state is trying to
have a durable system, the economics must be known for the time
when half of the state's oil is at an effective tax rate of 18
or 20 percent instead of 25 percent.
MR. PULLIAM said he will talk with the modeling folks at the
Department of Revenue who can run those types of scenarios.
REPRESENTATIVE SEATON further requested that those runs be done
going down to $50 per barrel.
MR. PULLIAM agreed to do so.
9:14:09 PM
REPRESENTATIVE TARR commented she is still having trouble with
the idea that, given it is so expensive to invest in Alaska, why
the tax credits are not a good idea. She asked whether [the
administration], when first contemplating a proposal, considered
adjusting progressivity for the higher prices that were not
anticipated at the time ACES was passed.
MR. PULLIAM answered that reducing progressivity was an option
he and others considered, such as going back to what the state
had under PPT or what was proposed originally under ACES before
the progressivity was increased or another way of reining in
that progressivity. In looking at all of the options, it was
concluded that a cleaner system, one that accomplishes the goals
over all that is wanted, is the one that eliminates
progressivity. The proposal eliminates some of the strange
incentives that are caused under progressivity and at the same
eliminates the credit. It is a more straight forward system and
it matches better with what is seen elsewhere. From the
standpoint of a company, the planning and investment decision
making will be cleaner and more straight forward. It removes
some of the problems with the decoupling issue, which is the
issue about when gas comes in and the effect on the state's tax
revenues. A similar issue to that, but on a smaller scale, is
the high cost heavy oil that he talked about and which has the
effect of reducing the tax rate and dramatically reducing the
state's revenue. He said he and the people at DOR and DNR felt
that this proposal is a "better mousetrap".
9:17:02 PM
CO-CHAIR SADDLER said he has heard it argued in committee and
elsewhere before that the economic limit factor (ELF) is proof
that low taxes do not affect production because taxes were lower
under ELF and there was declining throughput. Under ELF the tax
rates were different for larger and smaller fields; taxes on
large fields rose and production from those fields decreased,
satellite fields sprung up and net production from those fields
increased. He requested Mr. Pulliam to provide an analysis of
the argument that ELF proves that tax rates do not affect the
decline in oil production.
MR. PULLIAM replied he does not think a conclusion can be drawn
that low tax rates do not affect production and do not affect
investment, it is nonsensical. Clearly, there is a relationship
between the tax rate and the attractiveness of that investment,
it is basic economics. There is no causality between a decline
in production while there is a low tax rate. The time period of
ELF was a period of relatively low oil prices, about $30 per
barrel, and the cost for moving that oil to the West Coast was
$8 per barrel, for a netback of $22. Additionally, there were
the production costs, so what was left over was not a lot. This
was the same for both Alaska and elsewhere. Investment in
Alaska was going on at that time - Alpine had just been
developed and satellites around Alpine and Kuparuk were being
developed. Referring to the capital spending depicted on slide
17, he pointed out that investment in Alaska tracked the rest of
the world from 2003 to 2006 and it increased as prices went up.
Yes, production continued to decline during that period, but
that does not mean there was no activity going on. Newer fields
were being brought on, they just were not replacing all of the
oil that was going away from the declining large fields. So,
there was activity and investment going on in new fields during
those times of lower tax rates and it was consistent with that
in the rest of the world. In his view, he continued, the
decoupling occurs from 2007 forward, when the rest of the world
accelerates and Alaska stays flat.
9:21:00 PM
REPRESENTATIVE TUCK requested that slides 20-23 be done in the
same manner as was done for ACES, but for HB 72. He further
requested that columns be added for oil prices up to $140 and
down to $60.
MR. PULLIAM agreed to do so.
REPRESENTATIVE TUCK thanked Mr. Pulliam for his presentation,
the new information, and the opportunity to ask questions.
9:23:33 PM
[HB 72 was held over.]
9:23:40 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 9:24 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB04 Rep. Hawker & AGDC Responses.pdf |
HRES 2/13/2013 1:00:00 PM |
HB 4 |
| HB04 Legal Memo RE Judicial Review.pdf |
HRES 2/13/2013 1:00:00 PM |
HB 4 |
| HRES HB 72 EconOne Presentation.pdf |
HRES 2/13/2013 1:00:00 PM |
|
| HB04 DNR Response RE ROW Leasing.pdf |
HRES 2/13/2013 1:00:00 PM |
HB 4 |
| HRES HB 72 Econ One 2.13.13.pdf |
HRES 2/13/2013 1:00:00 PM |
HB 72 |