Legislature(2011 - 2012)HOUSE FINANCE 519
04/21/2012 02:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB3001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB3001 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
April 21, 2012
2:05 p.m.
MEMBERS PRESENT
Representative Eric Feige, Co-Chair
Representative Paul Seaton, Co-Chair
Representative Peggy Wilson, Vice Chair
Representative Alan Dick
Representative Neal Foster
Representative Bob Herron
Representative Cathy Engstrom Munoz
Representative Berta Gardner
Representative Scott Kawasaki
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Representative Lance Pruitt
Representative Dan Saddler
Representative Chris Tuck (via teleconference)
Representative Bob Lynn
Representative Kurt Olson
Representative Pete Petersen
Representative Mike Hawker
Representative Mike Doogan
Representative Tammie Wilson
Senator Cathy Giessel
COMMITTEE CALENDAR
HOUSE BILL NO. 3001
"An Act relating to adjustments to oil and gas production tax
values based on a percentage of gross value at the point of
production for oil and gas produced from leases or properties
north of 68 degrees North latitude; relating to monthly
installment payments of the oil and gas production tax; relating
to the determinations of oil and gas production tax values;
relating to oil and gas production tax credits including
qualified capital credits for exploration, development, or
production; making conforming amendments; and providing for an
effective date."
- HEARD & HELD
PREVIOUS COMMITTEE ACTION
BILL: HB3001
SHORT TITLE: OIL AND GAS PRODUCTION TAX
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
04/18/12 (H) READ THE FIRST TIME - REFERRALS
04/18/12 (H) RES, FIN
04/20/12 (H) RES AT 1:00 PM HOUSE FINANCE 519
04/20/12 (H) Heard & Held
04/20/12 (H) MINUTE(RES)
04/21/12 (H) RES AT 10:00 AM HOUSE FINANCE 519
04/21/12 (H) RES AT 2:00 PM HOUSE FINANCE 519
WITNESS REGISTER
WILLIAM BARRON, Director
Central Office, Division of Oil and Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Testified and answered questions during the
PowerPoint presentation related to increasing production during
the hearing on HB 3001.
TONY REINSCH, Senior Director
Upstream & Gas
PFC Energy
Washington D.C.
POSITION STATEMENT: Testified and answered questions during the
presentation by the PFC Energy on Global Strategy and portfolio
overviews of major Alaska producers.
ACTION NARRATIVE
2:05:38 PM
CO-CHAIR ERIC FEIGE called the House Resources Standing
Committee meeting to order at 2:05 p.m. Representatives Feige,
Seaton, P. Wilson, Herron, Munoz, Dick, Gardner, and Kawasaki
were present at the call to order. Representative Foster
arrived as the meeting was in progress. In attendance from the
House Special Committee on Energy were Representatives Pruitt,
Saddler, Tuck (via teleconference), Lynn, Olson, and Petersen.
Also in attendance were Representatives Doogan, Hawker, and T.
Wilson and Senator Giessel.
HB 3001-OIL AND GAS PRODUCTION TAX
2:06:12 PM
CO-CHAIR FEIGE announced that the only order of business would
be HOUSE BILL NO. 3001, "An Act relating to adjustments to oil
and gas production tax values based on a percentage of gross
value at the point of production for oil and gas produced from
leases or properties north of 68 degrees North latitude;
relating to monthly installment payments of the oil and gas
production tax; relating to the determinations of oil and gas
production tax values; relating to oil and gas production tax
credits including qualified capital credits for exploration,
development, or production; making conforming amendments; and
providing for an effective date."
2:06:57 PM
WILLIAM BARRON, Director, Central Office, Division of Oil and
Gas, Department of Natural Resources (DNR), began his PowerPoint
presentation titled "Potential for increasing production." He
stated he thought that barriers have been thoroughly discussed
[slide 2]. He stated that the next slide shows the length of
time it would take for industry to pull projects together in
Alaska [slide 3]. He explained that typically it takes from 10-
15 years from the time of initial exploration to production,
limited to the North Slope and new exploration, but not
necessarily Cook Inlet, seismic, in-field drilling, or
development drilling within an existing field. Referring to the
graph timeline, he said obviously a significant number of years
could be shaved off if the development is occurring in an
existing field. For example, a lot of construction time could
be removed, and a small add-on to a facility would also not
require feasibility, permitting, financing, exploration and
seismic studies so the project would begin with construction and
production.
2:08:50 PM
REPRESENTATIVE KAWASAKI referred to an article he saw in
Petroleum News several days ago that quotes the governor as
saying a meaningful change in taxes could result in production a
year or so out; however, he compared this statement to the
comment Mr. Barron made regarding tax regime changes and a
significant time lag on projects. He asked for clarification on
this.
MR. BARRON said he didn't think he could answer the question
since he was unsure of the specific quote. However, if a
company is working in Prudhoe Bay, Kuparuk, or Alpine - existing
fields on the North Slope - a company could go to construction
almost immediately. It also would depend on the size and scope
of the project so the construction phase might only span one
year or less. He suggested that adding on a small separator or
de-bottlenecking could also be done in a relatively short time
frame, so new well production could occur right away. He
related his understanding if that is the governor's context it
is correct; however if it is something different the lag could
occur between engineering and construction before first
production.
2:10:56 PM
REPRESENTATIVE KAWASAKI offered his understanding that Governor
Parnell said he wants to see a proposal to incentivize new
production in the existing fields along with new field
production and he believes that with significant tax change in
existing fields the state could see as much as 100,000 new
barrels per day within a year and a half.
MR. BARRON said that does mirror his comment with respect to the
overarching structure in the existing legacy fields. He
explained the timeline on [slide 3]. If existing infrastructure
is already in place, including roads, power, and facilities and
the work is limited to adding new wells, then production could
happen in a very short time frame. Further, work can happen
year round if new facilities are being put on existing pads.
2:12:19 PM
REPRESENTATIVE KAWASAKI noted that much of the discussion has
revolved around how to get new production out of the legacy
fields, including more work and more local hire. He asked for
comments with respect to HB 3001 and how the time frame would
shrink and big producers would want to produce. He pointed out
that even when the state had a low tax rate on existing fields
under the ELF, the state did not see additional investment.
MR. BARRON referred to a graph from Commissioner Butcher's prior
presentation. He said by going across the graph one can see a
tremendous amount of work is being done in that time frame. He
characterized it as a highly capital-driven curve that changed
the production profile for the North Slope, especially
considering the satellite fields, such as Endicott, Alpine, and
Kuparuk. Those fields were brought on during those same years,
which represent hundreds of millions of dollars' worth of
investment that stabilized the production profile. He
acknowledged it doesn't appear to be stable, but a line could be
drawn that would show the state would have been at 1 million
barrels production in 1995 if it weren't for all of this work
and if the state only had Prudhoe Bay. However, in 1995,
production was at 1.5 million barrels per day. He reiterated
that while 100 percent of the work might not have been
specifically directed at Prudhoe Bay, work was associated with
fields they were finding in and around that wonderful basin. He
emphasized this discussion must be framed in the context that
the Prudhoe Bay and North Slope area continues to remain as one
of the great oil basins of the world. He pointed out there is
an old cliché that says "If you are going to look for oil, look
in an oil field." This is reflected in the aforementioned
graph. The industry in total said that Prudhoe Bay is the
largest oil field in North America; Kuparuk is the second
largest oil field in North America; and North Star, Endicott,
Lisbourne, and West Sak are all within the primary boundaries of
Prudhoe Bay and Kuparuk. As companies continue to work, they
continue to flatten the production curve and change the
production profile with their investments. Every well that is
drilled has an impact on the decline curve of the Prudhoe Bay
field itself. Every time the company changes, it goes from
primary development - drill the well and produce it - to
secondary development, in which gas or water, or separation
facilities that change the overall draw down will change the
production profile. This is not a "no work" case, but rather
reflects the hundreds of millions, if not billions of dollars in
investments that have benefited both the state and the
companies. He said, "They do work; we make money; they make
money."
MR. BARRON asked members to consider, for example, that the cost
of an exploration well is $20 million if not more. He pointed
out that the Mukluk well [Beaufort Sea] cost $80 million, but it
was a dry hole. Furthermore, ConocoPhillips experienced trials
and tribulations to try to get a bridge on line at Alpine. He
concluded that this graph shows a tremendous amount of effort to
continuously flatten the decline out of our major fields.
2:18:10 PM
CO-CHAIR FEIGE, referring to the graph and the underlying
Prudhoe Bay production, said it appears that in 2007 the decline
rate was reversed for a brief time. He asked for clarification
on the change.
MR. BARRON responded that he will be able to provide additional
information at the next meeting, but at this point he is able to
say this represents a mathematical aberration. He explained the
Cartesian plot and production curves are either exponential
decline, which most of the fields are; however, part of this
effort was work associated with gas cap injection. He noted one
piece of work had a significant change in the production profile
in Prudhoe Bay. He again offered to address this further at the
next meeting.
2:19:27 PM
REPRESENTATIVE GARDNER referred to slide 3 and asked whether the
permitting time frame holds regardless of the type of oil field,
or if is there a significant variation.
MR. BARRON responded that there would be variations. For
example, if work is being done in an area which is primarily
uplands the permitting process will be shorter since it is not
necessary to obtain wetlands permits. He stated that with shale
oil development permitting will be difficult and complicated
unless it is located in high and dry uplands such as in Cook
Inlet.
2:20:38 PM
REPRESENTATIVE P. WILSON offered her recollection the ratio was
1:6. She noted that for every six wells drilled only one would
be "wet." She asked whether that statistic has changed due to
advanced technology.
MR. BARRON explained the ratio is primarily driven focused on
exploration, but not for development. He suggested a geologist
wouldn't be employed long with that type of ratio of success.
He said that with exploration the ratio can sometimes be 1:10
for successful wells.
2:21:35 PM
CO-CHAIR SEATON referred to the decline curve. He questioned
whether the division disagrees with comments offered by the
division to the U.S Senate Energy Committee. At the time the
division stated that with the exception of the development of
heavy oil resources known to exist around Prudhoe Bay, Kuparuk,
and Milne Point and the potential resource plays like the Bakken
Reserve in North Dakota that may exist on the North Slope,
natural field declines cannot be replaced without access to
production from federal lands and Outer Continental Shelf (OCS).
There are no known conventional resources on the state or Native
lands that are likely sufficient to replace the decline in the
existing production rates. He reiterated that this testimony
was given less than a year ago by the director, Kevin Banks.
MR. BARRON explained that sometimes the testimony focus is
obscured. He said those comments pertained to a plea to open up
OCS, Arctic National Wildlife Refuge (ANWR), and federal
properties to encourage that exploration effort - to open ANWR
up. The key phrase in his testimony refers to "known fields"
and just last year Brooks Range Petroleum (BRPC) has found a new
discovery of about 40 million barrels. When Mr. Banks made that
comment the field was an unknown field. He predicted that 40
million barrels will not reverse the decline at Prudhoe Bay, but
it will be a piece of the mix that will flatten it and begin to
turn the curve. He offered his belief that a change can be made
in every field by increasing investment to a certain point. He
suggested that a one percent change in Prudhoe Bay is 6,000 to
7,000 barrels of oil per day. That will be half of what the
BRPC's production will be. He related his understanding what
Mr. Banks was trying to convey to Alaska and the country is that
there is a limited ability to reverse and flatten the curve of
the major fields coming off of Prudhoe Bay and get back to 2
million barrels of production in existing fields; however,
access to ANWR and OCS would change this profile dramatically.
He agreed with Mr. Banks that no known field can reverse the
decline in the legacy fields and increase production to 1
million barrels per day, but it is the unknown that Mr. Banks
was trying to attack in his testimony.
2:25:26 PM
CO-CHAIR SEATON related his understanding that a tax change for
the known fields of Prudhoe Bay could reverse the decline. He
pointed out this seems quite different than Mr. Bank's testimony
in May when he said it will not be possible to reverse the
legacy field declines without federal lands and OCS. He asked
for clarification as to whether solely a tax rate change could
reverse the decline from legacy production - not incremental -
and provide a 10 percent increase in production.
MR. BARRON attempted to clarify that to reverse the production
profile in a field is possible with investment. He related that
the amount of the investment is dependent upon the type of
project and the point in the timeline of the life of the field,
since as one advances in time it becomes harder to change the
decline rate as the resource base is more limited. He asked
whether the producers can begin to flatten the curve of their
existing fields with increased investment. Technically, yes, it
is possible, he said. He asked whether the fields can be
reversed and become positive and he answered, yes, in some of
the fields it is possible although he cannot be specific since
he has not done calculations in terms of the total aggregate.
Further, he has not yet researched that particular issue;
however, all the production profiles can be flattened with more
investment.
2:27:55 PM
CO-CHAIR SEATON commented that is the crux of what the
legislature is trying to figure out, to decide whether a fairly
simple change in tax policy will reverse and incrementally add
ten percent above where the state is currently producing at
Prudhoe Bay. He said it seemed the division was saying a year
ago that incremental production within the known fields would
not reverse the decline and it would not be possible to achieve
accelerated production without federal properties or OCS.
MR. BARRON said that for him to say one percent change in
profile is 6,000 to 7,000 barrel per day translates to a
meaningful change. He was uncertain of whether one percent
increment is possible without the investment occurring to prove
it. Further technologies are available and new reservoir
management companies are engaged with could make it possible.
Additionally, areas that can continue to be developed can impact
production; however, it must be within the economic boundaries
and parameters of the companies to move forward with those kinds
of projects. He asked whether one company can stop the decline
and answered that according to the work agreement it is
possible. Therefore the state's goal should be to strive for a
collaborative and competitive basis so companies will want to
bring investment to the state and not send it somewhere else.
CO-CHAIR SEATON said he appreciated this since these are pieces
of the puzzle the state needs. He stated that what drives the
state is revenue. He acknowledged that production, price and
costs, and tax rates are part of the formula. The legislature
must work on revenue to the state. The legislature is trying to
construct a scenario to move the state to the right place in the
long term. He did not think there was a disagreement, but the
state is trying to figure out if the decline rate can't stop the
decline with in-field legacy drilling, then the state cannot use
a figure of "positive 10 or positive 20" on top of legacy
production to generate revenue curves. He summarized this
committee is trying to understand if it is possible to produce
10 to 20 percent more out of Prudhoe Bay by a meaningful tax
change.
2:31:27 PM
MR. BARRON acknowledged that point, and turned members'
attention to the next slide titled "Reasonably expected time to
production" [slide 4]. He suggested that part of what is being
discussed is the phasing of developments and exploration work
being brought into production. He said within the next 5-10
years - noting the darker the shade represents the more
likelihood of an impact - three primary areas can be brought in
to meaningful production. First and foremost, that can occur in
the legacy fields and some others within the geographic area.
This gets back to the heavy and viscous oil and the importance
of understanding the dilutant needed to produce it. Some of
that dilutant could be the lighter oil being produced at Prudhoe
Bay and Kuparuk today. Therefore there must be an orchestrated
effort between heavy and viscous oil and the light oil that is
produced. He highlighted that the industry is currently
examining how much light oil is needed to produce the viscous
oil so the companies' development plans have sufficient amount
of lighter crude to allow them to ship the heavier crude down
the line. He characterized this as all part of the same mix.
He noted the last well BP had running on a test produced 650
barrels per day of viscous crude, which is probably double the
world wide number for viscous crude. He said, "That is
incredibly positive." However, to so companies must have an
equal amount of lighter crude. He cautioned this process is
still in the pilot test phase, but their pump failed when it had
a tubing failure. They are working through that issue, but if
this work plays out, it represents a significant potential step
change for that area and it lies within the boundaries of the
legacy field. This would be a new probable development area
that is very robust, he stated.
2:34:29 PM
MR. BARRON stated the next potential is shale oil. He reported
that Great Bear Petroleum is on the cutting edge of shale work
and plans to drill three to four wells in the next quarter.
Thus the state will find out whether shale oil can be produced
and what kind of fracking must be done to develop those wells.
He stated that within the next five years these aforementioned
projects are the three primary areas that can be brought to
bear.
MR. BARRON turned to new discoveries as the next phase. He
pointed out that Brooks Range Petroleum Corporation is working
on viscous oil and more shale oil, which is not to say the
legacy fields are not important - the bar on the graph continues
- since they will still produce and provide infrastructure as
an advantage for some of the new discoveries.
MR. BARRON said the 5-10 year plus window will produce new
fields, more viscous oil, and shale oil. Outside of that, the
10 to 15 plus years, will be the Outer Continental Shelf (OCS),
Beaufort, OCS Chukchi, Arctic National Wildlife Refuge (ANWR)
and the National Petroleum Reserve-Alaska (NPR-A). He suggested
this in terms of how the industry and developments will be
staged, and in terms of the legislature's discussion relative to
tax policy. He summarized that this slide represents the
natural staging of impact to the production profiles.
REPRESENTATIVE KAWASAKI commented that despite the changes the
legislature makes, companies will make decisions based on a
grand plan, for example, companies will likely be using light
oil for heavy oil production in the future. He emphasized, from
a policy standpoint, the legislature wants to ensure that the
incentives are directed to provide more jobs, construction on
the North Slope, reduction on the decline curve, and local hire.
However, the recent testimony indicates the oil and gas
companies aren't considering those issues. He wanted to ensure
that the policy group will focus on the state's interests.
2:37:48 PM
MR. BARRON attempted to clarify that his testimony could be
misconstrued. He related his discussions with the project team
for heavy oil indicated the companies are cognizant that they
will need the lighter oil production as a dilutant for their
production. This isn't to say that the industry is not producing
what they can produce today, but rather that industry
understands some of their mechanical limitations will require
additional production. He related his understanding that
industry wants to ensure as the work is staged and orchestrated
with existing development - as it moves forward - to ensure the
product can be produced in a timely manner. Again, he
emphasized that industry is not withholding production or simply
not developing. The team he met with was saying was, "I need
that to be able to do what I need to do." He suggested that
waiting 15 years to produce heavy oil and staging it instead of
doing it concurrently might mean viscous oil production may not
happen. In fact, it's actually just the opposite of what might
be inferred since the team has been trying to figure out how to
accelerate their work to increase production in a timely manner
by pushing the technology and marrying the two projects
together.
2:39:35 PM
REPRESENTATIVE DICK referred to fracking and asked how that
technology could impact Alaska. He asked whether new technology
to extract viscous oil would ultimately have a negative impact
on Alaska if the technology is used globally since it might be
easier to use heavy oil in other places. He said he struggled
to understand the impact.
MR. BARRON explained that new technologies happen every day. He
highlighted that fracking is not new technology and has been
used by industry for over 100 years. He pointed out over 25
percent of Alaska's wells have been fracked, which most people
don't know; however it is the combining of technologies that
continues to advance the industry. He said he has been an
engineer and has worked in the field for over 35 years. This is
the third time the Bakken fields have come up as a development
play. Each time, it has stopped because of low production and
product price - primarily due to those two drivers. He said low
production was also due to technology since long-reach
horizontal drilling had not been invented nor did the company
have the ability to stage 20 or 30 fracks. He emphasized that
multi-stage fracks have been used in Alaska; however, in his
personal experience five or six fracks were all that was needed
and not 20-30 in a horizontal section. He asked whether it will
it ever be detrimental to the state to gain the foothold of
knowledge and he offered his belief that it is probably not a
disadvantage. He predicted that if the state's fiscal system
and the infrastructure in Alaska are competitive, the industry
will participate in the competitive environment. He has held
discussions with one company who came to Alaska due to the huge
resource basin, existing facilities and infrastructure. The
operators struggle with the cost of production, the cost of
labor, and product price. If one were to put aside the fiscal
regime, one would still have the three obstacles just mentioned.
He pointed out that the economic limit for shale oil wells will
be a key driver in the overall development and how much is
developed. For example, he stated the economic impact will
affect whether it will be economic to put on rod pumps. He was
unsure whether it would be possible in Prudhoe Bay due to cost.
He concluded that cost of operation is one of the biggest
hurdles in Alaska.
MR. BARRON related that the Permian Basin in West Texas has been
around for hundreds of years and it is still a prolific basin
with hundreds of rigs running. This is possible because
operating costs are significantly lower in Texas than in Alaska.
So, again, from a technology standpoint it would not ever be a
disadvantage and he predicted companies would aggressively
pursue viscous oil if Alaska developed advanced technology in
coordination with the development of the rest of the field.
2:44:40 PM
MR. BARRON referred to an exhibit from Bakken field passed out
previously by Co-Chair Seaton indicating a production profile of
a typical well in the Bakken field. He pointed out that this
profile represents one producer's average. He turned to the
Eagle Ford analog in the oil zone of Eagle Ford shale for
comparison [slide 5]. He said the graphs look a little
different, but if you take off the first part and compare it to
the curve of the Bakken field the curves are similar. It's
important to consider the scale on the bottom is in months and
not in years. He stated this is information received from the
Texas Oil Commission, which is his counterpart in the state of
Texas. He noted the scale on the bottom of the slide is months
not years. He predicted that the Eagle Ford basin is closer to
production than the Bakken field. He projected that in ten
months the Eagle Ford will be at 100 barrels per day. He
emphasized this goes back to Representative Dick's comments on
technology and his response relative to cost. In a very short
order those wells will be producing at 100 barrels per day.
MR. BARRON referred to several comments that people have made.
He explained the assumptions of the graph, which is the
potential for Shublik. The Eagle Ford analog is based on six
rigs drilling six wells per month or 30 days per well. He said
"drill, frack, complete, put on line. That's doable, but that's
six rigs - so six new wells - a month." He said this graph
assumes that every well has a 20 year life. This graph shows
the potential of 2,000 wells being drilled in that formation.
The initial production (IP) is 500 barrels per day. He pointed
to the graph, noting he has been a bit conservative with his
estimation; however, the final production at 30 barrels per day
and is projected at that rate for 20 years. However, he
cautioned that no one knows whether the wells will be around for
20 years. Eagle Ford and Bakken basins haven't been producing
horizontal fracked wells for 20 years. He asked members to
consider carefully what occurs when drilling is ceased and the
precipitous decline that ensues, which goes from 65,000 barrels
per day to 10,000 barrels in a matter of 20 years [slide 6]. He
said, "All of these wells are crashing - one right after
another." Of course, this is what one would expect to happen
based on the decline curve; however, by changing it just a bit,
based on five years of life, the red curve represents 20 years
whereas the blue curve reflects the change if the well only
lasts for five years and continues to drop and becomes un-
economic. Thus the profile would be even more dramatic [slide
7]. He said while shale oil is a very robust potential - and
Eagle Ford basin is only one of three zones - in the context of
impact, these wells are not highly prolific for very long, which
is important to understand as a state.
2:50:09 PM
MR. BARRON turned to slide 8 as his final slide, titled "What
will it take to reach the goal?" First, he emphasized the
importance of a collaborative and competitive environment to
reach the state's goal, noting the industry will respond to
environments that are collaborative and competitive. Second, he
stressed the importance to minimize barriers as much as is
possible especially within the agencies. Third, he emphasized
the importance to access all fields and recover all types of
oil. He highlighted that an integrated mix of fields and
developments will reverse and change the decline - whether it is
existing legacy fields or new discoveries in some form or
fashion. He concluded that technology will play a part in the
role.
REPRESENTATIVE GARDNER related he discussed things that Alaska
offers. She asked what role water would play since the use of
water and growing concern about disposal of waste has been a
critical issue. She asked whether water would be an issue of
concern.
MR. BARRON responded that at this juncture interesting changes
have occurred, with respect to the chemistry that would allow
using brackish water, and if so, he did not think water source
should not be a problem since even using sea water becomes
technically possible. The disposal of that water would then
fall under the purview of the Alaska Oil and Gas Conservation
Commission (AOGCC) and injecting and disposing wastewater
becomes their responsibility. He offered his belief that it is
technically doable, and in fact, many companies are considering
technologies to reuse a lot of that water for re-frack
operations.
REPRESENTATIVE GARDNER referred to slide 4. She described the
significance of the color fade and she wondered if there is any
significance to the different color text also.
MR. BARRON explained that he was attempting to illustrate that
it's not possible to estimate when gas infrastructure will be in
place. He acknowledged the gold band darkens over time. He
referred to the first green band on slide 4, which shows the
primary areas of impact as legacy fields, followed by heavy and
viscous oil, and shale oil, but still not necessarily a prime
drive. He highlighted that the coloration fades over time.
REPRESENTATIVE GARDNER surmised, therefore, that the legacy
fields would be the biggest expectation for new oil in Trans-
Alaska Pipeline System (TAPS).
MR. BARRON concurred.
2:54:28 PM
REPRESENTATIVE KAWASAKI asked whether a legacy field the size of
Prudhoe Bay and Kuparuk has ever increased or if the straight
line curve is to be anticipated.
MR. BARRON pointed out that Prudhoe Bay is unique since it is
the largest field in North America. He questioned finding an
equivalent analog. However, in terms of whether the field could
flatten or reverse the decline of the field, the answer is yes,
but it is very difficult. He mentioned that he will have some
exhibits at a later hearing that will demonstrate how the
primary producing area of Prudhoe Bay has been changed with
development and activity. He further suggested the team hopes
to provide similar examples from other areas to show the effects
of continuous work and technology.
2:56:09 PM
REPRESENTATIVE SADDLER referred to slide 7 and noted the
estimated 5 or 20 year life; however he also noticed a 32 and 47
year production life. He asked whether the change is due to
drilling ceasing after 5 or 20 years.
2:56:26 PM
MR. BARRON explained that slides 6-7 illustrate the time frame
based on an assumption of six rigs with each rig drilling one
well every month: drill, frack, complete, put on line in 30
days. He said he built the exhibit assuming 2,000 wells would
be drilled so once the 2,000 wells have been reached the
drilling would stop. He explained the production profile
existing from the curve. Thus as the individual wells producing
on this curve are cumulative, at the end of the day 2,000 wells
may not be producing, since some of the wells may have reached
their 20-year life and dropped off. The goal is to continue to
drill to reach the production profile; to reach the 2,000 wells;
stop; and finally achieve the natural decline. He highlighted
this would be an excellent example after drilling ceases of "a
no work case - for shale, not for conventional." He pointed out
that the graph shows the profile if the company stopped drilling
at year 28; however, if the company drilled more wells the
cumulative profile would change again.
2:58:24 PM
REPRESENTATIVE SADDLER asked whether high taxes cause a field to
stop producing at a certain point that otherwise would be
considered economic.
MR. BARRON suggested the commissioner said it best, that high
taxes, and high costs change the economic limit for a well. The
higher costs, including taxes, tend to drive the point when the
well is shut down since the company will not be making any
money. He agreed it can very easily change the value of when
the well is shut in.
2:59:11 PM
REPRESENTATIVE PETERSEN referred to slide 4, to the heavy and
viscous oil with shale oil right below it. He highlighted that
shale oil is a lighter type of oil so the development of those
two types of oil together could help solve the problem of oil
flowing down the pipeline. He asked whether that is a
possibility.
MR. BARRON agreed that is a possibility. He added that when he
met with the viscous team, the team was excited about the
prospects, but also recognized some of the technical challenges
- ensuring adequate dilutants. He recalled the ratio needed
would be 1:1. He related the team is still studying it and they
need latitude for continued research; however, if it is a 1:1
ratio, if the shale crude is of the right quality it could be
used to produce the viscous oil.
CO-CHAIR FEIGE announced that the final testifier would be a PFC
Energy presentation "Overview of oil and gas companies' Capital
Allocation Processes, Investment Decision Making & Global
Portfolios" by Tony Reinsch.
3:02:00 PM
TONY REINSCH, Senior Director, Upstream & Gas, PFC Energy,
stated that PFC Energy is an independent consultant and advisor
to the oil and gas industry, exclusively. The company counsels
and discusses strategy, planning, and development with
governments, regulators, industries, national oil companies, and
oil and gas producers on a global basis, and through the entire
value chain from upstream oil and gas development to refining,
distribution product markets, and the service industry. He said
he has been asked to share thoughts around company decision-
making as it pertains to budgeting, planning, and capital
allocation in order to shed light on how companies internally
make their decisions about capital allocation within portfolios.
This could extend to global comparisons of basins and investment
opportunities. He offered to discuss the metrics used for
capital allocation and de-integration to significant oil and gas
producers, such as Marathon and ConocoPhillips Corporation
(ConocoPhillips) separating their upstream and downstream
operations, including identifying drivers, pros and cons to that
fairly significant change in corporate structure. Additionally,
he said he will discuss capital allocation over the life of
basins and fields and net free cash flow moving from basin to
basin as the industry moves forward over time [slide 2]. The
second part of his PowerPoint presentation will cover the global
portfolios of the three large integrated major oil producers in
Alaska: BP Global, ExxonMobil Corporation, and ConocoPhillips
Company.
3:06:00 PM
MR. REINSCH discussed the "Annual Planning Cycle" [slide 3]. He
referred to the annual process that all oil and gas companies
follow in their annual budget cycle process. He pointed out
this slide illustrates that in the first quarter of each year
companies will undertake a review of their strategy vis-à-vis
the world. He related that in the second quarter companies
review the new things they might begin, followed by budget
preparation in the third quarter, and lastly by the budget
approval process.
3:07:33 PM
MR. REINSCH referred to "Strategy, Planning, and Positioning
[slide 4]. The strategy begins with an outlook for the future
of the world, usually covering a 15-20 year outlook taking into
account the global economic performance and impacts on energy
demand, competitor analysis, and geopolitical considerations
that may impact oil and gas global markets. Each company has
preferences for basins and jurisdictions they work in and review
these options with an eye towards above ground risks, changes in
the operating environment, and potentially defining new no-go
geographical areas where companies will not do business or open
basins in which companies were not previously interested in
engaging such as the shale oil gas plays in North America. The
companies will consider the operating environment issues,
including discussions of any blockers, enablers, gaps, and
logjams that could get in the way of their plans. Companies
will review the environmental, including taxation systems,
market outlooks and what competitors are doing, which is an area
that PFC Energy engages in to a considerable extent. Companies
are interested in knowing who else is doing what they are trying
to do and where they might run into competition. Companies will
assess information and come up with options and plans for where
they will move next and what they will engage in.
MR. REINSCH referred to the "Annual Planning Cycle" [slide 5].
He stated this information would be transferred into dollars and
cents in the budget preparation. He referred to the "Planning
Cycle and Capital Allocation" Corporate Input: Common
Assumptions on External Environment" [slide 6]. He indicated
each business unit will update its long-range plan, five-year
plan, and ultimately the budget preparation on the basis of
common assumptions. He related that this capital allocation
competition begins this process since each unit highlights
opportunities they believe are in the best interest of their
company and are best able to impact and deliver the strategy and
objective for the company. The corporate section rolls it into
discretionary and non-discretionary capital expenditure (Capex),
and it is recycled until the figures are appropriate and it
moves to the board for approval, to allocation of capital, and
project approval and execution. In response to Representative
Saddler, Mr. Reinsch answered that no importance should be given
to the color gradations on slide 6.
3:11:54 PM
MR. REINSCH related the final piece of the annual planning cycle
is the budget approval and allocation of capital in November and
December of each year and then the cycle begins again [slide 7].
The question, within that cycle then becomes how a project -
large or small - attracts capital within that process. He
stated a number of considerations come into play: materiality
to the company, full-cycle economic performance metrics, and all
of the considerations of whether an oil and gas company "IOC"
will position or continue to invest in a particular asset,
basin, or country [slide 8]. He identified the types of
projects that Alaska is accustomed to seeing are multi-year
duration projects and long-term production. He pointed out that
all projects can be broken into discrete investment decisions or
stages. This creates a stage-gate that the board of directors
and senior management can stop, amend, or accelerate for the
ongoing activity.
MR. REINSCH related the buckets of discrete investment
activities are considered project approval requests and
companies will take those forward for approval by senior
management. Clearly, if the issue is drilling a set of
technically difficult wells, the project approval request can
extend beyond a given budget year. He said what defines the
activities is that they are discrete in a larger body of work
with a beginning and an end. Each project approval request
(PRA) has an approval for expenditure attached to them for
specific activities. These stage-gates are points in which the
company will make a determination regarding whether to continue,
amend, or suspend activities on a given project and field or
basin. This allocation level represents the point at which
Alaska competes within the portfolios of all other companies to
attract capital - not in the absolute sense - but in a relative
sense in competition with all other parts of the world.
3:15:38 PM
MR. REINSCH discussed the "Business Control Architecture" which
illustrates six budgets laid out on the center of the charts and
three competing streams of activities over time [slide 9]. He
pointed out the green bars, and noted this company is looking at
a new basin in year two and at the end of that work the board
makes a decision regarding whether to continue to exploration.
In this instance, they decided to move on to exploration with
the Approval for Expenditure (AFE). He clarified one way to
consider their process is that the finances lie in the project
approval process and the approval for expenditure (AFE) is just
presenting the paperwork for payment and no decisions are made
during the AFE process.
3:17:23 PM
MR. REINSCH referred to the beige bars on the slide titled
"Appraisal PAR" and "Development PAR" which move beyond
exploration to appraisal [slide 9]. Fields will often be
appraised and a decision will be made not to develop the
project, but instead to divest or "park" the project and await
infrastructure maturation. For example, the McKenzie Delta is a
classic example in which ample resource was discovered, but it
stopped at the appraisal stage. The top bars on this slide
indicate "Exploration PAR", "Appraisal PAR" and "Development
PAR." He pointed to the vertical capital slices in year three,
shown by the dotted line. He indicated that adding up all of
the AFE approvals represents the capital budget for the project
and this process is the process used within these companies to
develop their budget.
MR. REINSCH highlighted that some activity "bleeds" into the
fourth year, which becomes non-discretionary capital to the
"Year Four" budget. He noted a certain amount of the capital
budget that has already been approved and committed will show up
in subsequent years.
3:19:49 PM
MR. REINSCH discussed the "Upstream Financial Metrics:
Measuring Performance" [slide 10]. He noted this slide shifts
to assets, how asset performance is measured, and how attraction
is determined when securing capital within a budget. He
highlighted that performance is measured in different ways,
including growth, profitability, efficiency, cash flow, and
risk. He defined growth as the ability to manage the top line,
or increasing the volume of production. He identified the first
measure of performance as growth, and the compound average
growth rate (CAGR) relative to target, or the measure of whether
the project has been able to deliver according to the plan. The
quality of the growth includes the ability to maintain growth
and whether the acreage is inadequate to maintain growth. The
plowback rate would really be a measure of how much is being
reinvested back into the assets and shows the relative growth
intentions between different regions. Second, would be
profitability or the ability to manage the bottom line. He
stated that upstream cash flows, upstream net income, and
upstream production costs are all measures of how well the
company is doing in a bottom line sense or the revenue net of
cost. Third, he defined efficiency as the ability to manage
capital with the most common metric being the return on capital
employed (ROCE). He highlighted that finding costs - resource
found relative to exploration dollars - is finding and
development costs (F&D) to bring the resource to market and
replacement costs, such as how much it costs just to stay even
or the per barrel cost of production. Fourth, he identified
cash flow measures as the ability to manage investment or re-
investment in the company's portfolio. Issues such as debt-to-
capital ratio and dividend requirements also become important,
too. He pointed out some companies are focused on dividends
whereas others - particularly smaller independent companies -
are mandated to reinvest all of their net revenue. In response
to Co-Chair Feige, he clarified several acronyms.
3:23:01 PM
MR. REINSCH identified the compound average growth rate (CAGR)
as a measure of compounded growth over time as opposed to
average growth, which is taking the end year and initial year
and simply dividing it. He explained that compound average
growth provides more of a rate or acceleration measure. He
stated that the return on capital employed (ROCE) will be
discussed in more detail, but is used to determine whether a
company will undertake an activity using a number of benchmarks
or metrics. He discussed the "Project Selection and Decision
Metrics [slide 11]. He highlighted a few metrics that are
common in the industry and defined them: Pay-out period is the
length of time required for capital return, which is a major
consideration for smaller oil and gas companies, but is
important for all companies; the internal rate of return (IRR)
is one of the most common measures used to rank projects; and
the net present value (NPV) is the measure of how much value the
investment activity is bringing to the company. He noted that
the present value of cost minus the present value of revenues
should be greater than zero. He pointed out this as another way
in which a hurdle rate can come into play.
3:25:24 PM
MR. REINSCH highlighted that net present value is often
expressed relative to production or barrel of oil equivalent
(BOE) to obtain the present value per barrel of oil produced,
which provides a different measure of investment efficiency. He
said the net present value (NPV) is what would be generated
relative to the amount of investment or dollar of investment for
a project. He clarified that it is often referred to as a
present value per investment (PVPI) dollar measure, as well.
REPRESENTATIVE GARDNER asked whether the assessment of return to
the investment dollar incorporates various internal goals that
companies may have.
MR. REINSCH answered that a particular asset may fit within a
portfolio in a different way between companies. For example,
ExxonMobil may review the long investment strategy and may
notice a hole in the company's portfolio in ten years that a
particular technology could fill. Thus investing in that
technology may help acquire a wall of cash flow that the
technology would generate. He acknowledged some technologies
may have a place in one portfolio, but not in another. In
further response to Representative Gardner, Mr. Reinsch agreed
metrics must be taken in context and must fit together in a
certain way. He was unaware of any company that makes
investment decisions based on one measure of performance, but
rather will decide how these different measures fit together
vis-à-vis the rest of the assets in the portfolio. He related
that some of it depends on timing, but also depends on when the
company can undertake large scale or capital projects or
development.
3:29:03 PM
CO-CHAIR SEATON asked whether any average expectations are held
by industry for infield drilling on the payback or payout period
or return on capital versus new development or if it is company
specific.
MR. REINSCH answered that it is very much asset and activity
specific decision. He related that reviewing capital projects
with six-year investment cycles would typically have a longer
payout. For example, one of the reasons deepwater developments
are currently sized rather than sized to have an extended
production plateau is to generate the return to that capital as
fast as possible. He suggested that one would need to make a
strong case to industry if the capital is exposed for three or
more years.
CO-CHAIR SEATON related the legislature has been considering
legacy fields versus non-legacy fields. He questioned whether
90 days is the typical payout period or if that would be
considered a short time frame. He reiterated he is interested
in the payout period and what it would mean to investment
decisions.
MR. REINSCH offered that if he saw a capital investment activity
with a 90-day payout period he would want to check the IRR, the
NPV, mature reality, and PVPI to determine how the other
measures line up. He suggested that the payout periods
represent the simplest and least instructive of the many hurdles
a project will need to go through to attract capital. He
concluded that if the payout period is over three years for
almost any investment that management will look hard at what the
project is attempting to accomplish.
3:32:16 PM
CO-CHAIR FEIGE sought clarification regarding the factors and
subjectivity for which projects go forward and which don't.
MR. REINSCH answered that he has been describing the science of
the decision-making process. He agreed all of the metrics are
assessed for available projects, which are put into the models
and ranked in many different ways. The science has been taken
to the extent of creating efficiency frontiers and portfolio
analysis, but generally speaking what is missing is the art. He
said that solely modeling has not been found to be optimal for
the company's strategy. Furthermore, what is being invested
will impact what the company will be in three, five, or ten
years from now, which needs to be taken into account. He
characterized the process as a combination of science and art.
He suggested that if one can't overcome the hurdles then the
project isn't considered. He highlighted that a certain minimum
requirement exists for assets to compete for capital and passing
all the hurdles doesn't necessarily mean capital will be
attracted; however, at least the project would be in the
running.
3:34:55 PM
REPRESENTATIVE P. WILSON related her understanding that any tax
regime must be fair since it is up to the companies to decide
which project fits into their portfolio best.
MR. REINSCH answered that one of the challenges faced by
resource owners is that assets compete with each other within
their portfolios and with basins around the world; similarly,
the fiscal system in Alaska competes against all other fiscal
systems in which these companies are engaged. He said the
presentation will cover what each of these three companies is
looking for with respect to growth by examining their
portfolios. He noted in some cases, companies will focus on
North America and for others the focus is somewhere else. He
described this as part of the challenge that the business owners
face. For example, an asset may be a great asset, but it may be
located in Iraq so that specific asset will compete with a
deepwater well in the lower tertiary of the Gulf of Mexico.
Clearly, this example represents an "apples and oranges"
comparison, but that is what is involved. He responded that
there is an onus which increases depending on how reliant a
jurisdiction is on oil and gas revenue for its budget and future
to ensure they have the ability to have a dialogue with industry
- financial and technical - to arrive at comfort on both sides
of the table. He emphasized the importance of understanding
these assets, such as an enhanced oil recovery program or terms,
such as ultra-heavy oil to fully understand where the challenges
lie and to be able to determine when the challenges are not as
severe as being represented. He characterized the process as
client-contractor negotiations.
3:38:46 PM
CO-CHAIR SEATON asked where on the chart the net income per
barrel of oil equivalent (BOE) comes in terms of comparing
regions or projects.
MR. REINSCH asked for clarification on whether the question is
if the number could be compared between basins or projects.
CO-CHAIR SEATON answered yes. He said the state has reports of
net income per BOE from Alaska versus other jurisdictions in the
U.S. The legislature has been making judgments on tax systems.
He asked which relationship the legislature should examine with
respect to net income barrel of oil equivalent (BOE) on Alaska's
projects versus other projects and whether that should be a
metric that is considered.
MR. REINSCH answered it is not an either-or metric such that the
highest net income per barrel of oil equivalent (BOE) wins. He
highlighted that the materiality element is one in which the net
income per BOE doesn't really shed any light on. Further, small
fields with substantial infrastructure can generate good net
income for BOE numbers since they may only need to bring the
product to surface since pipelines and the processing plants
already exist. He said the infrastructure has been paid for by
prior activity based on tariff so it is difficult to compare
that scenario against development that brings fields into
production without any infrastructure. The first development
may have net income per BOE numbers that are not particularly
attractive, but every subsequent development will benefit from
the infrastructure. He also said this is almost a "more is
better" argument, but it doesn't necessarily make the project a
better one from the company's perspective. In further response
to Co-Chair Seaton, he agreed it could be due to scale,
materiality, or growth issues and if a project can be turned
into something core and material to the company.
The committee took an at-ease from 3:41 p.m. to 3:59 p.m.
3:59:18 PM
CO-CHAIR FEIGE called the meeting back to order.
MR. REINSCH referred to the term "maximum negative cash flow
exposure," which he defined as really a measurement of financial
capital requirement. Clearly, major capital projects such as
LNG developments or integrated mined oil sands can involve
billions of dollars of capital exposure prior to any revenue
being generated. The question of the maximum exposure for a
company and how much the company can afford to undergo is
critical. He emphasized two major companies have almost "come
to the wall" by having major capital programs that were
exhausting their ability to finance - Chevron [Corporation] and
Shell [Global]- and in both cases high oil prices saved the
moment. He stated that net book reserves are important because
bookable reserves determine the value of an oil and gas company.
One of the reasons companies are not willing to engage in fee
for service contracts such as Mexico offers - where the company
is not allowed to book barrels to take ownership - is because
without that ownership there isn't an increment of value to the
company. Finally, the capital expenditure per barrel of oil
equivalent (Capex/BOE) or the cost per barrel of production
capacity burdens the project by the cost of infrastructure and
facility requirements necessary to get the product to market.
He concluded this tends to favor projects that are less complex,
being undertaken in well-established geographic environments
with ready access to infrastructure.
4:02:18 PM
MR. REINSCH focused on "Net Present Value (NPV)" and "Internal
Rate of Return (IRR)" [slides 12-13]. He explained NPV as the
value of a project when all future net cash flows are discounted
to the present at an appropriate rate or discount factor such as
cost of capital to the company. It may be the company's cost of
equity or debt, which is the difference between all of the
revenues anticipated from a project and all costs that will
burden a project are discounted to a single point in time. For
example, he stated that if an NPV is greater than zero, arguably
the project is worth undertaking in an economic or commercial
sense. That means the specific project is expected to at least
generate a competitive return to the capital being invested or
what it will cost to invest in that project. Clearly, NPV that
is less than zero would represent a project the company would
not even consider, but NPV in and of itself is not a selection
criterion.
MR. REINSCH related the advantages of NPV, including that it can
be calculated exactly, risk can be accommodated, for example, to
enable a comparison between an investment in Alaska with one in
Angola, Uganda, or Russia. This is done by "risking" those
flows of capital and revenue, or to discount the revenue flows
to reflect likelihood of interruption. He stated that the
discount rate allows a company to identify cost of investment
capital to undertake the projects, such as using the cost of
equity, raising funds in the capital market, and the cost of
debt or a weighted average of the two to use as the discount
factor.
4:05:02 PM
CO-CHAIR FEIGE asked whether the discount factor or appropriate
rates are interest rates.
MR. REINSCH answered not necessarily, and in fact, very seldom
would it refer to the interest rate. While it is reflected in a
formula as an interest rate, normally a company would use some
representation of the cost of capital. It could be the interest
rate to borrow or it could be the difference between long-term
versus short term borrowing. Further, it could represent the
cost of equity to the firm. He suggested that if a company must
raise capital as opposed to borrowing, it would be much more
expensive. Companies want to reflect when an undertaking will
require the company to go to capital markets and raise equity to
undertake the development. Thus, the discount factor will vary
pretty significantly from company to company. The one most
often used in the literature around the industry is an NPV 10,
which means a 10 percent discount factor. He noted each company
would have its own representation for the NPV.
4:06:35 PM
CO-CHAIR SEATON said he was struggling with the discount rates.
He related his understanding that if one area was secure the
company wouldn't use an NPV 10, but if there are problems or
insecurities that a company might use an NPV 12-15, but he was
unsure how to incorporate discounting the cost or the revenue
flows.
MR. REINSCH explained that this is being debated in the
industry. There are situations in which a company will use a
discount factor of 10 for North America and 15 for Uganda and 22
for Mozambique. The problem with taking that approach is the
discount rate has such a huge impact - since it discounts
present value. He characterized it like using a blunt
instrument when looking at the portfolio of opportunities. He
noted that as soon as the discount rates are changed it
basically takes away the ability to compare projects. More
appropriately, it would be better to use a single discount rate.
He pointed out that in a risky environment what is at risk is
the revenue flow. He suggested discounting that or adding a
factor which would still allow an "apples to apples" comparison.
4:08:29 PM
REPRESENTATIVE FOSTER asked whether the profit premium is
included. For example, if you are using the NPV 10 percent
since the shareholders are requiring as a return, the effect is
to back it up to zero, which would be the breakeven point. He
asked whether the profit premium is built into the revenue
stream or the NPV figure. He suggested that operating in Angola
would require including a risk premium. He reiterated he is
trying to figure out where the profit premium is built into the
NPV.
MR. REINSCH answered that the NPV is the amount greater than
zero. Ideally, a company would not want any profit margins or
add-factors built into the base cost and revenue stream. Thus
the revenue should strictly be the price times the quantity,
with costs being the operating costs estimated over the life of
the project. The interest rate would be applied to that and if
the NPV is greater than zero this project is generating a profit
margin; then it would depend on the NPV amount greater than
zero. Then the company would start comparing projects.
REPRESENTATIVE FOSTER clarified his understanding is the profit
is built into the revenue stream that is being discounted.
MR. REINSCH responded that profit is built in to the extent that
those discounted streams represent revenue and cost. For
example, if the NPV exceeds the NPV of cost, the company is
generating a profit. He stated that if the discount is an
appropriate discount rate representing the cost of capital, the
returning capital would already be accounted for a returning
capital - normal or competitor return - which is why the
appropriate discount factor would be the cost of capital so
companies make sure that is in the analysis as part of the
calculation.
4:10:50 PM
REPRESENTATIVE GARDNER asked where lease clauses and mandatory
development time lines would be factored into the decision
matrix.
MR. REINSCH said he would expect them to be reflected in the
revenue stream. In the particular NPV calculation this would be
part of how to determine the quantity number by which price is
multiplied. He explained that if a requirement to develop
within a certain time frame existed then, presumably, those
volumetrics being modeled represent adhering to those
requirements so those types of restrictions would help define
the project as its being modeled.
REPRESENTATIVE GARDNER surmised, then, that if by this date
there is not a flow then the leases would be pulled; however she
asked whether something more nebulous like a commitment or
obligation to develop - a duty to develop - have any place in
these calculations.
MR. REINSCH said it wouldn't have such a place and to model a
project somehow violating that wouldn't make sense. He said
that any project being considered would presumably be adhering
to the regulatory or legislative requirements for pace or scale
of development. For example, if the government imposed a
unilateral adjustment in government take in Israel from 35
percent up to 60 percent, basically, this would be saying the
company found the resources so now the take will increase since
the basin is de-risked. He suggested that that type of
unilateral move is very difficult for companies to accommodate
since it wasn't in their modeling in the first place. He
offered his belief that changing the rules part way through
without grandfathering in the terms creates a real challenge for
this industry on a global scale.
REPRESENTATIVE GARDNER surmised that risk was also factored in
the modeling.
MR. REINSCH responded no, not in that case; however, he noted
the quid pro quo for that is if the fiscal terms change to allow
for another avenue of commercialization. In that case the
company in question is arguably in a much stronger position for
export. He said, "Yes, we've discovered all of this resource
and yes, we've built up 35 years of domestic coverage at
projected growth rates for your country, now let us export the
rest - so there's give and take in this."
4:14:36 PM
REPRESENTATIVE HERRON questioned what the ideal NPV would be if
an NPV greater than zero is the minimum result in the formula.
MR. REINSCH answered that NPV is a dollar measure so it would be
in the millions or billions of dollars. He explained that you
can't rank with the NPV since it's not a hurdle in that way, but
it gets the company on the table. A large NPV doesn't
necessarily mean that this is the best project either.
Sometimes revenue streams can be so far in the future that they
are heavily discounted so looking at one metric in isolation
would lead a company not to undertake a project that really
should be undertaken from the perspective of the treasury, such
as an LNG development in Qatar being a case in point.
4:15:47 PM
MR. REINSCH moved to the second metric, which is the internal
rate of return (IRR) [slide 13]. He explained to reflect back
on NPV as the amount greater than zero, or the net positive
contribution of a project using a given discount rate across all
projects, that the IRR calculates what discount rate it would
take in order to equate all revenue flows to all capital costs
or costs incurred. The higher the rate at which those two flows
are equal, the more valuable is a given project. He highlighted
that IRR lends itself to a comparison across projects and is one
of the hurdle rates often used in industry. The biggest
disadvantage to the IRR is that multiple rates of return are
possible for any project when volatility in cash flow exists.
He noted that large positive and negative swings in revenue over
the life of a given project - decision makers like to have
unique decisions - and IRR does have that weakness, but clearly
it is for an exceptional type of project. He highlighted that
for the majority of project the IRR is a metric that can be used
for project comparison.
4:17:54 PM
MR. REINSCH gave an example of a project moving through this
process, with a number of metrics brought to bear, including an
NPV 10 greater than zero, a PVPI greater than 1.3, and payback
less than three years. This appears to be a good project and
looks like a project that should be undertaken [slide 14].
However, a common situation may arise - as is often the case -
that the company has more projects than capital. He pointed out
even with $100-$130 per barrel oil that a good chief financial
officer will impose discipline on a company by setting an IRR
level as one of the thresholds that the project will need to
succeed. Projects which don't meet that would become capital
returned to shareholders. He suggested it isn't just about the
projects, but that at some point it makes more sense to buy back
shares or give the money back to shareholders than it does to
invest in new project developments. He emphasized that
ExxonMobil is very disciplined and aggressive about this vis-à-
vis its shareholders and division policies.
MR. REINSCH suggested that whether you are a smaller company
where capital constraint is a reality of life, or a much larger
company where capital constraint is being created through
financial discipline, every company has more opportunities than
available capital. To bring that discipline to bear, the
company subjects its portfolio to different financial or
performance metrics, for example, showing IRR with a
hypothetical hurdle rate at $60 per barrel. He pointed out
higher IRR is better. Thus by aligning all projects from
highest IRR hurdle rate to lowest, and applying a metric or
cutoff such as using $60 per barrel as the IRR hurdle rate will
determine which projects receive funding. He pointed out the
little green bracket shows the subset of projects which will
receive funding and all other projects below that rate will not.
4:20:54 PM
MR. REINSCH discussed issues with the IRR hurdle rate. He said
that an increase in cash flow due to a rise in energy prices in
turn increases the capital budget and leads to a lower hurdle
rate in order to undertake additional projects. Thus the
company would be increasing its financial capability. Generally
speaking that will in turn lower the overall quality of the
portfolio. He explained the company would be undertaking
projects the company wouldn't otherwise have undertaken simply
because the company has more money at its disposal. He
suggested that at some point the company will have a floor to
reach or the project will not be funded. He pointed out that
cycles of value destruction within the industry do occur when
companies have a lot of money and "go out looking for the next
big thing" such as the six wells drilled by Cairn Energy
offshore Greenland. He asked members to consider how many times
wells have been drilled offshore Greenland. He surmised it is
in the geologists' minds that something is there so geologists
continue to look, but examining periods with high prices with a
lot of surplus available allows companies to chase some of the
higher-risk potentially higher-return opportunities.
4:22:34 PM
MR. REINSCH pointed out that IRR is a measure which if used too
exclusively can lead to "gaming" within the internal competition
for capital. Project managers would have an incentive to
overstate the "size of the prize" to attract investment capital
to a proposed project, which could boost the IRR. He stated
this as one of the reasons industry in the past 5-10 years has
been increasing the degrees of discipline within exploration
analysis to try to minimize this from happening. He said one of
the many elements that IRR does not speak to is materiality. He
stated that projects can have equivalent IRR's but much
different Capex or revenue profiles. Thus a small Capex
development with a relatively small revenue stream can quite
easily have the same IRR as a very large project with a very
large revenue stream, but those two projects will have very
different meanings to the treasury.
4:24:06 PM
REPRESENTATIVE HERRON asked whether the companies decide to set
a specific percentage.
MR. REINSCH answered yes. He suggested that a few companies
have been using a domestic versus an international IRR hurdle,
such as 15 percent for domestic and 20-25 percent for
international projects. He described this as arriving at a
level of corporate comfort or a different way to reflect
differences in the aboveground environment. Additionally, for
many companies, such as TransCanada, it may result in never
receiving any share value of an enviable portfolio for
international pipelines since its shareholder base didn't care
about it at all. For example, at one time TransCanada was in
Argentina, Chile, and Australia, but it didn't bring the company
any value. He agreed that discipline will be imposed
differently by companies when setting the hurdles.
4:26:31 PM
MR. REINSCH referred to "Portfolio Efficiency: Return on
Capital Employed (ROCE)" [slide 15]. He explained that the
return on capital employed (ROCE) is what the company receives
from capital it is exposing. He defined it as the net profit
divided by gross capital times 100 to arrive at a percentage.
He explained that ROCE is positively correlated with production
and commodity prices. These two elements will increase the
numerator, all else being equal, and it is negatively correlated
with capital spending. If a company spends a lot of capital
without positively impacting production, it will show up as
deterioration in the ROCE - and companies are very sensitive to
this. He characterized ROCE as a measure of how well management
uses the capital that has been put at their disposal by the
owners and creditors.
MR. REINSCH said over time, the ROCE will develop a pattern of
time series that will give investors insights into whether this
company is becoming more profitable or less profitable. He
suggested analysts would question whether management is creating
value or if it is it destroying value. He pointed out that ROCE
on an annual year-by-year basis isn't an overly meaningful
variable, but the implications are inescapable when viewed over
time.
MR. REINSCH referred to the chart on slide 16 "Portfolio
Efficiency: Return on Capital Employed (ROCE) One of the
issues arises when a company has been investing a lot of money
in a development that has yet to return production - a major
capital project - the ROCE will penalize the company. This
measure penalizes companies for that type of undertaking, which
is why it is seldom to see companies with high growth rates in
terms of production and high capital efficiency. He said with
the exception of a very few types of assets, such as oil sands
or LNG development of a large scale gas resource development,
nearly all other development assets have decline rates. He
pointed out that a significant amount of money is spent to bring
these projects into production, but as soon after production
they fall away in terms of production volumes. He highlighted
that companies will move in and out of the high-growth quadrant
versus high-efficiency quadrant, it is pretty hard to live on
the upper right hand side of this chart.
4:30:36 PM
MR. REINSCH said large capital project developments that deliver
lots of production for a year or two are projects that provide
ROCE. Thus ROCE is biased against major capital undertakings,
but it has a bias towards large assets. This puts companies in
a bit of a dilemma. Finally, anything that makes the
denominator smaller while the numerator is unaffected will be a
positive so depreciation creates a bias towards mature
portfolios. Generally speaking, the more mature the asset
portfolio, the higher the return on capital employed numbers.
4:32:01 PM
REPRESENTATIVE HERRON referred to the graph on slide 15 and
asked whether the best place would be at the intersection of the
two graph lines.
MR. REINSCH answered that best place to be is in the upper
right-hand quadrant as far as possible. In this particular
analysis, the axis is the average of growth and the average of
return on capital employed. Each year the axis moves, but high
growth and high return on capital employed is where companies
want to be so, referring to the graph "Global Players Peer
Group: Growth v. Efficiency," where Petrobras and ExxonMobil
live versus where ConocoPhillips has been for a period of time.
REPRESENTATIVE HERRON asked whether ideally, for stability, a
company should be located close to the intersection of the axis.
MR. REINSCH explained if a company has a very large portfolio,
producing 4 million BOE that it is very hard to grow. These
companies do not pay a lot of attention to growth, but instead
pay more attention to the ROCE. He suggested with large
portfolios that are difficult to grow, the company is just
trying to keep up with declines in an efficient manner;
otherwise shareholders will walk.
MR. REINSCH suggested that a chart describing Apache, Anadarko
Petroleum Corporation and others of that size would show much
lower ROCE numbers, but much higher growth numbers. Those
companies tend to focus on growth. The objective is to grow the
portfolio more efficiently, but at a rate competitive with or
superior to their peers, which is how they attract shareholder
loyalty and capital.
REPRESENTATIVE GARDNER referred to the net profits tax. She
asked whether that would make the state stronger in terms of
ROCE.
4:35:20 PM
MR. REINSCH answered if a company is involved in new field
development and is placing capital at risk and the government is
supporting the company by reducing that denominator - return on
the capital and capital in the denominator, the ROCE - once
producing - will be better than without that incentive.
However, the impact of this type of government engagement in
asset development will be better measured in IRR, and NPV for
specific projects than it will in ROCE only because ROCE is more
of a portfolio-wide measure. Even in the context of the Alaska
business unit for one of these companies the measureable impacts
will be on a project-by-project basis.
4:36:41 PM
CO-CHAIR SEATON asked whether the credits would be calculated in
the denominator, or whether the total project cost will be shown
no matter whether a credit exists or not.
MR. REINSCH related his understanding the question is whether a
company will incorporate government exploration credits or other
incentives in its project analysis. He answered that that good
companies will conduct their project analysis "clean" using 100
Capex and 100 percent revenue flows as a stand-alone and then
consider government incentives. If a project passes muster and
is economic without incentives, clearly incentives will improve
the economics. If a project only becomes economic due to
government incentives, then it becomes a management decision
because government incentives are more or less stable depending
on the regime involved. So at a minimum there would be an alert
that the project is not economic without the incentives being
offered. This "flag" would be attached to a project regardless
of the location.
CO-CHAIR SEATON asked for clarification on the ROCE calculation.
He asked whether the ROCE is put forward by the companies or
whether the companies will consider the total capital of the
projects and therefore it will not show up as credits.
4:39:01 PM
MR. REINSCH answered that the ROCE is a measure of portfolio
performance so the capital employed is the exposed capital.
Further, ROCE represents a data point not a forecast; so what is
being measured is actually corporate capital expended. The
denominator will consist of the company's capital commitment
relative to the returns being generated from the investment. To
the extent that incentives mean the company has been able to
leverage its capital, they will enhance the portfolio from an
efficiency of capital perspective. He said, "Absolutely, if the
government is going to assist with project development that
should improve the performance of that portfolio from a company
perspective."
REPRESENTATIVE MUNOZ asked whether PFC Energy is able to assess
the impact that Alaska's Clear and Equitable Share (ACES) has
had on the capital allocation decisions for Alaska.
MR. REINSCH deferred to his colleague, Janak Mayer, who can
better address that question.
4:40:43 PM
MR. REINSCH noted that PFC Energy was asked for insight on the
issue of integration versus de-integration within the major oil
and gas companies. He asked to layout the context for this
discussion. He reported that in 2010 Marathon Oil Corporation
(Marathon) and in 2011 ConocoPhillips both took steps to
separate the downstream operations - refining and marketing
operations - from the upstream. The result was to de-integrate
their upstream operations from the downstream operations, which
was a significant move for any company to make. This
essentially created two stand-alone trading entities, which
raised questions on whether this would be the next move by all
of the major integrated companies like Shell [Global], Chevron
[Corporation], BP, and ExxonMobil. Further, he was asked
whether de-integration would have an impact on ConocoPhillips
and Marathon's decision-making process and the potential impact
on the dialogue between Alaska and these companies. He answered
that several slides illustrate arguments for and against
integration and provide reasons for the companies' actions and
if this will become widespread [slides 17-18]. He stated that
companies have integrated and asked whether the arguments are
still in place.
4:42:25 PM
MR. REINSCH discussed the "Special issue: Integration versus
De-Integration." One of the founding arguments for integration
is that over the course of the commodity cycle as oil prices
fluctuate product cycles can move counter or provide a buffer.
In other words as oil prices decline, product prices don't
respond as quickly so if products, sales, and oil sales within a
company's portfolio, the company has a bit of a buffer for those
cycles. The counter argument is that even though downstream
profitability has collapsed, there have also been "pure play"
refining companies that have been quite capable of operating in
this environment. So it doesn't appear to be an argument any
longer for integration.
MR. REINSCH highlighted that molecule management has long been
another argument. He explained that molecule management ensures
sophisticated refining capacity is in place for particular
crudes - very waxy, very acidic requires a certain type of
refinery feedstock - so integration allows companies to build
refineries for the specific crude. The counter argument is
independent energy producers have not had any problem
interacting with the refining sector so that doesn't appear to
be an issue, as well. Additionally, there are specific oils in
which molecule management seems to be necessary, but companies
are addressing the issues through contract and joint venture
rather than through integration.
MR. REINSCH related another argument has been that integration
is a technical differentiator amongst energy companies to
enhance their ability to secure projects. For example,
companies could build a large refinery so they are viewed
differently by national oil companies or stewards of the large
non-equity accessible resources globally. The counter argument
is that the ability to build a refinery doesn't have a whole lot
to do with the ability to efficiently operate in the upstream so
what credit would integrated companies obtain versus a pure
refining company who only performs refinery development. The
most recent argument is that integration allows participation in
the downstream [Organisation for Economic Co-operation and
Development] (OECD) growth story. He said that in the
developing economies of China, the Middle East, and India, being
able to operate in the downstream by building refineries and
manage product markets allows companies to participate more
directly in the development. The counter argument is that in
these regions, many of which are dominated by national oil
companies or something similar, these companies are choosing
partners on the basis of what they bring to the table. He
pointed out that if companies need upstream development, they
will go to the best exploration and development companies and if
they want a refinery built, they will go to refinery
specialists. He acknowledged there was a time 20 to 30 years
ago, one company would provide all of the [upstream and
downstream] work. Thus time has eroded much of these arguments.
4:46:42 PM
MR. REINSCH discussed the arguments against integration [slide
18]. One of the biggest arguments against integration is that
capital markets appear to value integrated company below the sum
of its parts. He said that much discussion was held with regard
to BP Exploration (Alaska) Inc. with respect to the aftermath of
Macondo when BP's share price was in decline. He recalled
analysts suggesting that BP should be broken into pieces and
sold off because the individual assets were worth more than the
company was worth. He said the argument against this is that
costs are incurred so it is expensive to split a company. He
suggested that if any value can be derived by keeping these
assets together one should do so. One strong value that
continues to exist is the synergy between refining and
petrochemicals. He highlighted that Total Company [French
energy] and ExxonMobil have large refining and petrochemical
operations and would be reluctant to split those operations.
4:47:41 PM
MR. REINSCH related that the second argument has to do with
strategic focus. In many integrated companies, the downstream
sector is neglected strategically at the expense of upstream
positioning and growth, particularly in the current climate of
narrow refining margins and sustained, high oil prices. He
suggested that by taking these companies apart and creating a
management team dedicated to downstream they should be able to
create more value with that capital base than in the larger
company.
MR. REINSCH offered the third argument against integration is
materiality. There are very few materially, physically
integrated oil companies left. For example, by removing
Marathon and ConocoPhillips out of the mix, the exhibit on slide
18 shows refining capacity versus upstream production. He
highlighted that there are only a handful of companies with
significant refining capacity and secondly these companies are
not just refining the company's own product. He emphasized that
there are two business models going on here. As he previously
mentioned ExxonMobil and Total Company both have a strong
integration between refining and petrochemicals and would not
likely want to break those functions apart.
MR. REINSCH noted that the three other large players - Statoil ,
ENI, and Repsol YPF - are companies that were to a greater or
lesser degree national or quasi-national oil companies for their
respective countries: Norway, Italy, and Spain. He suggested
these companies would likely face considerable government
opposition to de-integration. The final and fairly significant
argument against integration would simply be that the world has
evolved. There was a time when it was important to control the
value chain from the barrel produced to the gallon sold at the
service station, otherwise one risked exposure. He pointed out
that in this world of more flexible and liquid trading, futures
contracts, contract sanctity, and product differentiation
specialization have eroded the benefits from integration that
really defined this industry years ago by and large isn't there.
MR. REINSCH provided an example. Forty years ago the debate
about security supply was a debate about physical barrels, but
now security supply is about contract terms. The dialogue has
changed about integration.
4:51:16 PM
MR. REINSCH summarized the discussion by relating how PFC Energy
sees the pros and cons concluding. He said it certainly appears
that share appreciation is the number one driver for de-
integration. Within certain companies there is a belief that by
separating the management teams, management focus, and
strategies of these operations which have no driving need to be
integrated that there is more value to be created than the cost
of taking them apart. Therefore de-integration makes sense from
that perspective. The market development arguments that existed
in the past for a downstream presence have largely ended and
arguably one of the last frontiers that was the case was in
Africa, and even there BP, Total, Shell are divesting their
refining and product marketing activities to pure play refiners
and marketing companies who perform these services as a
business.
MR. REINSCH noted his third observation is that internal
decision making and the increased sophistication of regulation
of this industry on a global basis has really taken away any
value companies may have derived from cross-subsidization or
barriers to competitor entry that being integrated allowed them
to secure. Those activities simply don't exist to the extent
they did so the value has eroded in terms of a return to
integration argument.
4:53:36 PM
MR. REINSCH said that although there are technical drivers for
integration, the same benefits can be secured through joint
venture agreements and contracts where third party refiners
don't need to be secured through physical ownership. He offered
PFC Energy's overall conclusion is that to the extent there is
further pressure for companies to de-integrate, it will come
from share appreciation arguments, with Chevron and Shell being
the companies that PFC Energy thinks will most likely be the
recipients of this type of pressure.
4:54:31 PM
REPRESENTATIVE PRUITT asked, related to materiality, for the
reason that companies such as Statoil, Eni, and Repsol would
have considerable government opposition to de-integration. He
asked for clarification on whether they feel a need to have the
upstream and downstream connection.
MR. REINSCH explained in all three companies that the
governments no longer have a majority share. It is more of a
legacy sense of responsibility for managing their domestic
market environment. So while all three companies are no longer
in the national oil company arena, they are all still dominant
players in their domestic current markets. Governments and
people consider them as champions of the energy sector so to de-
integrate and sell off one element or another would be construed
either a weakness or counterproductive.
4:56:12 PM
REPRESENTATIVE PRUITT related his understanding that even
companies such as BP and Shell were at one point nationally
owned. He asked whether the three previously mentioned
companies would be moving towards de-integration if it were not
for the political pressure.
MR. REINSCH stated that since all three are European companies
the dialogue would progress because pure play refining companies
and pure play marketing companies that would pay to access the
assets. The companies are not receiving a premium to own along
the value chain. He offered his belief that the discussion
would advance, but the legacy element and culture in the
domestic markets are not worth the expense relative to what it
would cost to take that step.
REPRESENTATIVE PRUITT recollected his conversations with Statoil
confirmed that it is a pride issue.
REPRESENTATIVE HERRON referred to product demand growth regions
of China, Middle East, and India [slide 17]. He asked whether
the committee should keep these countries in mind as members
consider HB 3001, since they will pay a premium for petroleum
products.
MR. REINSCH responded that regardless of what happens in Alaska,
the state will remain exposed to international pricing. He
explained that in the past a company could offer to develop the
hydrocarbons, build the refineries, and manage another country's
products, which presented a powerful argument; however, in these
high demand growth jurisdictions that cachet no longer exists.
These countries have their own national oil companies and
refineries since all are capable of managing their upstream,
midstream, and downstream businesses. For example, BP recently
executed with Reliance Limited Industries (Reliance) in India
for pockets of expertise BP doesn't have. He stated that BP, a
premier global deepwater developer, struck partnership with
Reliance to gain access to a large swath of acreage in the
Krishna Godavari (KG) Basin in India. This made sense for India
because India didn't have that degree of deepwater expertise;
however, for BP to build a refinery might elicit the response of
whether BP could do it any better than a refining company, and
if not, BP must compete with everyone else. He summarized that
to be a downstream player the company must compete with other
downstream competitors.
5:01:13 PM
REPRESENTATIVE PETERSEN related his understanding the old school
of thought about vertical integration was that a company would
have control of the product from the beginning through retail.
He sought clarification that more countries are moving to
specialization because there is less capitalization involved in
being vertically-integrated, since more business segments are
necessary, but specializing would allow a company to be better
able to make a profit.
MR. REINSCH acknowledged that is part of the argument. He said
that until relatively recently there weren't specialized
refining companies or specialized product marketing companies
since it wasn't easy to break into the stranglehold held by the
integrated players. The only real success people had was in the
upstream. He agreed that companies who are allowed to focus on
one end of the value chain who perform well can be more
competitive than integrated companies that spread management
expertise, focus and strategy across all elements of the value
change. Some integrated companies are recognizing this fact, as
well, since the competitive forces will improve returns and
result in more efficient capital expenditures.
5:03:31 PM
CO-CHAIR SEATON related that this part of the presentation will
discuss ConocoPhillips de-integration and the difference in
ConocoPhillips's perspective as an upstream company versus as an
integrated oil company. He expressed interest in hearing PFC
Energy's perspective as well as the relationship between the
three North Slope integrated oil companies, who will become two
integrated oil companies with a partner just upstream. He
pointed out that ConocoPhillips did not normally buy leases for
exploration, but currently did so. He asked whether this is the
type of thing the state could expect from an upstream
materiality focus.
MR. REINSCH explained that what has happened with ConocoPhillips
and what he predicted would increase in the next two planning
cycles is emergence of a de-integrated pure upstream player;
however it is one with a new chief executive officer, new board,
and a new executive fully exposed to the discipline of the
market. Clearly, he said, the company will be looking for a new
strategy and direction. He also said, "One of the questions I
know - I have no doubt it's asking itself - is what role does
Alaska play in that new direction." He pointed out that the
Alaska portfolio has a different meaning in materiality within
the ConocoPhillips upstream portfolio, global, than it does for
BP and ExxonMobil. He said Alaska can "turn the dial" on the
ConocoPhillips global portfolio, more so than it can for either
BP or ExxonMobil given the same change in investment environment
or change in production volumes. Alaska fits well with the
strategy that ConocoPhillips has as a company with the majority
of its assets resident in industrialized, developed economies.
Thus relative to its peers ConocoPhillips resides in safe haven
environments. The other side of the coin is that safe haven
environments tend to be mature basins, with relatively high
costs which makes it more difficult to balance the issues, thus
engendering discussions of fiscal systems. He suggested that
other than a sharpened focus on upstream metrics by the
management team, it doesn't really change the dialogue - Alaska
still needs to fit within that portfolio, and Alaska needs to
show that it is part of the solution to their strategy, targets,
and objectives since that is what these companies look for to an
extent.
CO-CHAIR SEATON asked whether ConocoPhillips's participation in
exploration leases was in anticipation of this new focus.
MR. REINSCH was uncertain, but acknowledged their de-integration
has been planned for some length of time so certainly it would
fall within that time of influence so arguably it would
represent some positioning with de-integration in mind.
5:08:43 PM
MR. REINSCH discussed the "Special Issue: Basin Designation and
Allocation of Free Cash Flow" [slide 20]. He stated that there
has been a fair amount of discussion in prior presentations in
the Senate Finance and Resource Committees about designations of
areas. He highlighted six definitions to allocate basins
within the global portfolios. The "core area" is really an area
that produces a stable stream of net cash flow and is material
to the company. He pointed out that a core would be of a much
larger size for ExxonMobil than for Apache. He referred to them
as the driving portfolios for growth for these companies.
MR. REINSCH defined a "focus area" as an area where companies
are investing capital with an eye towards growing through new
source production and reserves growth into cores. Typically, a
focus area is a net consumer of free cash flow. Cash flow would
come from other areas of the portfolio and would be a portfolio
in the investment phase. He defined "new venture" areas as
areas new to the company and less mature assets, such as initial
exploration and positioning, but still are consumers of capital.
Generally speaking there would be little or no production, he
said.
MR. REINSCH highlighted the fourth area as "harvest areas."
These are areas that produce net cash flow - revenue greater
than costs - with investment at or below a replacement level.
In other words, the company would be investing to maintain
production or manage a decline. All harvest areas have some
form of limit to growth, whether that would be due to geological
potential, competitor landscape, or limited room to run. These
areas tend to be the areas of "portfolio churn" where larger
companies will gradually sell off assets for a variety of
reasons, such as the asset is not performing well, or the
company cannot put management time or technical time towards
continuing to develop, or the asset doesn't represent as an
attractive an opportunity as something else in the company's
portfolio. He emphasized that when speaking to harvest areas,
he is not talking about entire countries or basin areas. Within
any given basin, mature fields may be going into decline that
perhaps could be managed through intensive enhanced recovery,
but generally speaking these consist of the mature fields in a
company's portfolio.
MR. REINSCH suggested that within those same basins new field
developments or new opportunities may represent "focus areas" or
"new ventures". He provided a classic example, noting the Gulf
of Mexico shelf region has been in production decline for an
extended period of time. The majors were largely leaving the
shelf and the assets were picked up by smaller companies who
have been working the assets more intensively. At the same
time, the most recent examples in the lower tertiary, in the
ultra-deep water areas, have seen very large resource
discoveries taking place. So while the Gulf of Mexico has
definite harvest assets and components, as a basin it also has
significant areas of new venture activity and focus activity.
It is important that everyone understand what is meant when
speaking of harvest areas. He explained when one is managing a
decline, or investing at or below replacement of production, as
an ongoing business practice, that would be defined as a harvest
asset.
MR. REINSCH pointed out that in a competitive operating
environment the assets would gradually be rolled over. He
defined "sit & hold" as a category that applies more to the
national oil companies than the publically-traded oil and gas
companies. Some companies hold large amounts of acreage and
just sit and wait for a variety of reasons, including that the
fiscal terms don't make sense to engage, or the aboveground
risks - political, social, or military - are too great to engage
in now. Finally, he defined the "exit/potential exit" areas.
He related that PFC Energy takes the portfolios of the companies
they follow and allocate them into these definitions of basin
designations.
5:15:41 PM
REPRESENTATIVE PRUITT referred to harvest areas and recalled him
mentioning companies typically sell off harvest area holdings.
He acknowledged the state has seen this happen in Cook Inlet,
but not on the North Slope. He asked whether he foresees this
as moving in that direction.
MR. REINSCH characterized Alaska as a whole as being in a
harvest mode. Alaska has had a set of legacy assets in decline
for some period of time, yet those assets are still valuable for
reasons beyond the producing horizons - due to the
infrastructure - which will allow for commercial development of
close-in fields of less attractive resource in terms of
viscosity or crude oil type. Yet the leveraging of the
infrastructure for prior investments can allow those resources
to be brought to production in the most efficient and economic
manner. So companies are staying because they still see
potential, he concluded.
MR. REINSCH raised the argument, in terms of the context of this
discussion, noting companies have opportunities for investment,
but not all resources are alike. For example, very heavy crude
oil has a different value than light, sweet, crude oils and that
difference must be reflected. Additionally, high-cost enhanced
recovery has a different cost base than natural reservoir
pressure in terms of producing the next incremental barrel of
crude oil. He pinpointed this as the argument being focused on.
MR. REINSCH said the legacy fields are in decline, and companies
are investing to keep the decline rates at 6 percent, rather
than 12 percent, but all of the capital in the economic
investment has been vetted, approved, pitted against all other
opportunities in the portfolios, and has succeeded in attracting
capital. The next step is "the next dollar" where the
discussion moves to, which is all commercial. He cautioned that
will be taking the decline rate from 12 percent to 6 percent.
He wondered about the next step, noting Alaska has potential new
growth in and around the legacy asset, and some potential in the
Chukchi Sea, where a new set of considerations come into play,
particularly from the perspective of this committee.
5:20:00 PM
MR. REINSCH suggested the real question is how to maximize
revenue for all parties. He referred to the chart titled
"Global Ares of Upstream Operations" to Alaska, which is
depicted as the blue "harvest" areas. He explained the blue
reflects the assets that are generating free cash flow from the
production fields and generally speaking, in a global portfolio,
will go to other opportunities.
5:20:46 PM
MR. REINSCH discussed the "Special Issue: Basin Designation and
Allocation of Free Cash Flow" [slide 21]. He indicated Alaska's
oil fields were built from the net free cash flow generated from
other producing jurisdictions globally. He referred to two
charts "2003-2005: Sources & Uses of Cash Flow" for a large
representative set of companies and "2008-2010: Sources & Uses
of Cash Flow." He explained the first chart represents a macro
look at the industry, in which North America and Europe were the
cash engines driving deepwater development in Sub Saharan
Africa. Five years later Europe has still been producing cash,
but it is largely Sub Saharan Africa that has been generating a
large wall of cash directed to North America. He predicted as
the clock rolls forward three years, that cash will be used to
develop the next basin, whether it is Angola pre-salts or the
equatorial margin of Northern South America, since billions of
dollars of capital will be required. He highlighted that Europe
has typically been the cash cow of this industry for two
decades.
5:22:57 PM
REPRESENTATIVE HERRON noted that Repsol YPF is listed on the
bottom of slide 21. He asked whether yesterday's events in
Argentina by [President] Kirchner will affect Alaska.
MR. REINSCH predicted that the events will impact Repsol. He
explained that three days ago on April 10, the president of
Argentina enacted the renationalization of YPF - the state oil
company that Repsol purchased in the late 1990s and has operated
ever since. Over the years Repsol bought 92 percent of that
company, and while Repsol has reduced its equity position to
about 57 percent, it still represents 60 percent of its total
global production. By renationalizing YPF it took over 51
percent of the company from Repsol - not from publically-traded
shares in the market - but from the Peterson Group - an
Argentine owned company with 27 percent of the company it holds.
He predicted the law will be enacted by May 6th or May 7th,
noting the legislation has a three-year negotiation window of
settlement with Repsol before arbitration in an international
court.
MR. REINSCH stated this impacts Repsol in two ways. First,
Repsol lost 60 percent of its base in one fell swoop. On the
other hand, Repsol lost the element of their portfolio that was
dragging it down as a corporation. While YPF generated cash
flow, the asset was still a difficult, mature operating
environment. He explained that Repsol has been a very
successful exploration company the past four or five years and
has assets the company can grow. The advantage has been that
Repsol' s portfolio looks much better, although it could use $10
billion to invest in the company. While the Argentine
government may settle with Repsol, it is uncertain if this will
happen and it might occur after a lengthy legal contest. He
concluded that this is a very difficult situation for Repsol.
Outside of Repsol, a number of companies in Argentina are likely
wondering whether this represents a great consolidation
opportunity or if it is time to step quietly to the side and
focus elsewhere. In response to a question, he answered that
PFC was not the consultant the Argentinians used.
5:27:04 PM
MR. REINSCH, in response to another question, explained the
reasoning in the legislature is that security of supply is an
issue of national interest. He said that arguably the drivers
for that decision were reflected in the twin capital account
deficits and an inability to raise international finance since
Argentina defaulted on their debt three years ago. Further,
Argentina did not have access to capital markets and already
eliminated expropriation of profits from the energy sector for
any company operating in the country. At the same time
Argentina operated under a system of subsidized oil and gas
prices to protect consumers from international prices.
Therefore, Argentina prompted energy demand growth at a time
when they were importing significant amounts of natural gas. He
recapped his belief that Argentina was in a box and observed
free cash flow being generated by the YPF portfolio and saw an
opportunity to address two issues. First, Argentina could
secure the cash for the government; and second, by allocating
the 51 percent - half to the provinces and half to the federal
government - it could address some long-standing federal
provincial issues plaguing the country. He pointed out that by
hammering YPF for six months prior to the legislation being put
forward drove the share price down to a point where the
government will have a good argument during the settlement to
Repsol. He referred to it as policy in a crisis and he surmised
that everyone will argue at the end of the day it probably
wasn't the best policy move, but it is too late to change the
decision.
5:29:27 PM
MR. REINSCH discussed slide 22 titled "Example: Nexen Inc." He
explained the portfolio allocation of free cash flow in action.
He explained the bottom right hand side of the slide is a chart
which reflects the global representation of Nexen Inc.'s
portfolio (Nexen) and the status of the company. The left-hand
side bars show combinations of cash flow and Capex over time
starting in 2000 and moving to 2010. He pointed out that Nexen
had an asset in Yemen - the Masila block - that generated a
tremendous amount of cash flow with relatively little capital
expenditures and on the basis of the cash flow were able to
secure and develop the North Sea Buzzard assets. The very
generous cash flow from their North Sea portfolio has allowed
them to pour capital into the development of their Long Lake oil
sands and unconventional gas assets in Canada, and in the U.S.
Gulf of Mexico deepwater assets. One can see how the company
has redirected its free cash flow from one set of assets within
its portfolio to develop another and it will continue to do so
over time. He pointed out that reviewing any upstream
exploration and production companies will demonstrate that same
movement of cash flow over time. Clearly, part of the
discussion has been that Alaska wants to be part of the
portfolio that is receiving capital and wants to grow production
as opposed to being part of the portfolio that is only
contributing to developments elsewhere.
5:32:27 PM
REPRESENTATIVE GARDNER asked whether other companies were in
harvest mode or exit mode in the UK North Sea during the time
Yemen cash flow was used to bring new volumes on line in the UK
North Sea.
MR. REINSCH responded that Nexen was able to secure the UK
portfolio of a company called EnCana that had decided to shift
its strategy from becoming the largest global independent to
becoming the largest gas producer in North America. This
resulted in strategically stranding some very high-value assets
outside North America. Nexen was able acquire the asset
portfolio on the strength of its Yemen cash flow and financing
capability. He pointed out that Buzzard at that time was just
being developed as the largest oil discovery in the North Sea in
the prior 20 years. He characterized it as a real jewel, which
Nexen could acquire since Nexen had the Yemen asset developed
and has been generating large amounts of cash flow on an annual
basis. Thus Nexen could afford to make that move, develop the
asset, and then afford to make the next move.
MR. REINSCH, in response to Representative Gardner, confirmed
that the sale of the UK North Sea portfolio by EnCana was a
classic case of arguably commercial economic assets being
divested for a strategy purpose. He said that EnCana took the
money it generated from the North Sea and invested it into North
America because EnCana believes North America's gas prices were
heading to $5 and higher in 2000-2001. He suggested that EnCana
had a different vision of the future than other companies did.
He suggested that no one would have sold those assets purely for
economic or commercial reasons, but the assets were sold as a
strategy driver.
5:35:35 PM
REPRESENTATIVE DICK acknowledged that the oil companies say they
need a more favorable tax regime, which is fairly broad.
However, the legislature is trying to determine what specific
changes will bring about the desired outcome.
5:36:57 PM
MR. REINSCH suggested that part of the challenge in Alaska is
that Alaska has quite a diversity of investment opportunities
from well-established legacy fields, to untapped gas resources,
to high viscosity heavy crudes, and to frontier exploration
plays. He offered his belief that the question becomes much
more subtle, such as what are Alaska's goals in one to three
years, in three to five years, and in five to seven years.
Further, it's also a matter of how Alaska can align those with
the capability of the industry to deliver. For instance, if the
state's goal is to achieve production to the extent it can be
flattened in the next three to five years, the goal can't be met
by exploration. He pointed out the cycle time from exploration
to discovery to new production. One of the reasons PFC Energy
can speak so firmly about portfolios is that if it will "turn
the dial" for any of the companies in the five- to seven-year
time frame, the resource is already discovered and PFC Energy
has already modeled it. He said, "That's what we do." If the
state is looking beyond that the next exploration potential in
the next two to three years will have an impact 7-10 years from
that time. He stressed that it is what the state already has in
the bank - enhanced recovery on those assets - or what is soon
to be brought into production, which is the focus. He
acknowledged that may take a different set of fiscal action
responses. Then the state must review its portfolio and
recognize that these assets will decline. No one wants to
destroy capital so the question becomes what can the companies
deliver and what do they need to attract that capital.
Companies can invest here, but have the choice to invest in
another jurisdiction.
MR. REINSCH said the great advantage Alaska has in this global
gas discussion is that Henry Hub is completely irrelevant to
Alaska; however, that it not the choice at Lake Charles
[Louisiana], since Henry Hub is everything to them. He asked
whether anyone is going to liquefy LNG in the Lower 48 and send
if off to Europe or Asia, with a $4 spread. He pointed out it
wasn't that long ago that gas was at $7 and there were reasons
it dropped. The beauty of being in Alaska is that gas isn't gas
in Alaska, instead it is oil. He characterized gas as S-shaped
curves sold into an Asia market at crude prices so it is a
different dialogue; however it will also require a different set
of incentives. He asked whether the state would only benefit
from revenue or if it would be possible for the state to benefit
through gasification as happened in Columbia, Argentina, or
Brazil. He pointed out that these countries used the gas to
wean themselves off petroleum products which were expensive for
them. He cautioned that although no company can predict if the
state does this, the companies will do that; all they can really
say is that if the state does something it will help. Beyond
that, it is important to consider reasonable scenarios so
everyone involved is coming out of this in good shape, which is
the art of fiscal economics. He said, "Don't kill the golden
goose, but on the other hand, you are the client; they are the
contractor."
5:42:45 PM
REPRESENTATIVE SADDLER asked for clarification on slide 22 for
the example for Nexen, Inc.
MR. REINSCH explained that the chart on the left reflects on the
horizontal axis cash flow in millions of dollars, and on the
vertical axis shows capital expenditures (Capex) with $2.5
billion at the top and $2 billion in cash flow on the right. So
in reviewing Yemen - note the thickness indicates tracking,
which starts thin and gets thicker over time. He explained the
large capital expenditure in the 2000s in Canada, before the
cash flow moves the bar to the right. This is the time that
Nexen was spending building up its Long Lake oil sands
development, which came into production only three to five years
ago. The result is the line moves to the right and down showing
the cash flow with relatively less investment. He referred to
the UK on the cart, and noted Nexen bought the asset when it was
already in production, and basically it developed a large wall
of cash flow and they've been able to maintain it. He pointed
out the U.S. Gulf of Mexico reflect asset sales and purchases,
large capital expenditures and cash flow resulting from
production. The dominant assets are in the UK and Canada. He
pointed out that after bringing the Masila block into production
in the early 80s when it came to the end of its license life,
the government decided to take it back. He said the
contribution of Yemen was the North Sea and Canada portfolio, as
well as the seeds of the West Africa portfolio that hardly show
on the graph since the asset is just now coming into
development. He related that Nexen leveraged that legacy asset
into a lot of growth elsewhere in the world. In further
response to Representative Saddler, he explained that Nexen
spent $2.7 billion to buy the asset in about 2006 and in the
second year of capital expenditure spent about $700 million.
Nexen has basically been spending an annual amount of $700
million per year on the asset. In 2010, Nexen performed new
platform development and field work so the Capex was a little
higher and cash flow a little lower.
5:48:09 PM
CO-CHAIR SEATON asked what relevance the aforementioned
discussions on cash flow have to do with Alaska's situation
since Alaska is trying to incentivize in-field drilling and
legacy fields. He offered his belief that these evaluations on
cash flow would have more to do with company board room
discussions. He said he did not think Alaska would base its
decisions on incremental in-field drilling since it is unlikely
a 600-million barrel field will be produced in three or four
years.
5:50:24 PM
MR. REINSCH explained that sometimes the scale muddies the
process; however the process would be exactly the same. He
pointed out with certainty the 600 million barrel fields lie in
places that companies don't want to be operating. For example,
a company does not want to drill in 6,000-7,000 feet of water
through 500 meters of salt to get to production formations that
have never been produced in the world before to drill wells that
cost millions of dollars - whether it is in Brazil, Angola, or
the Arctic - if it is ExxonMobil. On the complete other end of
the spectrum, an investment of $6-8 million for horizontal
multiple-fracked shale gas in a liquids-rich shale basin in the
U.S. represents a small investment with a nice competitive
return, albeit not as nice at 3 Mcf.
MR. REINSCH acknowledged the company would want to obtain a high
volume of liquids at that rate, and if so, portfolios would move
as a result. Alaska would like to see the investment in
enhanced recovery in in-field drilling or other reservoir
sweeps, such as more sophisticated water handling techniques to
increase recovery rates, which is every bit as comparable to
opportunities the committee has referenced. It would just be a
matter of scale at both ends. This is why companies don't look
only at [net present value] NPV, except from a strategy sense,
such as considering investment in Angola over a 20-year forecast
of the basin. At the end of the day, part of this analysis will
boil down to a pure barrel of oil equivalent (BOE) metrics. He
said, "I'm going to put a dollar in here, what am I getting out
of it." The company will run the economics at $40, $60, $80,
$100 and $120 per barrel of oil pricing. He recalled the term
"harsh oil" or "severe oil world," which has been used since the
easy oil has all been exploited. All of these developments
carry risk so companies will always consider their analysis. He
was asked how an Alaska enhanced recovery project compares to
all of these and answered that it truly competes for capital.
If that's what Alaska wants to incent, there are ways of
incenting an enhanced recover project, which seems to be the
crux of the debate, he said. He cautioned members against
concluding that companies are involved in very large scale
developments all around the world so how could Alaska possibly
compete, which is not the issue. Instead, the issue is that -
outside of the strategic aspects of positioning - these metrics
give senior management and executive boards a way of comparing a
dollar in Alaska to a dollar elsewhere within the global
portfolio, to allow them to make the most efficient, effective,
profitable decision in the interests of their shareholders and
their investors. He concluded this is essentially exactly the
same thing Alaska is doing.
5:55:06 PM
REPRESENTATIVE P. WILSON said she has heard complaints in the
legislature that legislators did not obtain any commitment from
companies. She related her understanding from Mr. Reinsch's
testimony that companies cannot give Alaska a commitment because
companies must take their decisions back to their boards.
MR. REINSCH confirmed this.
REPRESENTATIVE DICK suggested the analogy that the legislature
is being asked to pull a lever, but they don't know how hard to
pull. He expressed interest in learning more about the cause
and effect between what the legislature decides and the desired
end result.
MR. REINSCH agreed with Representative Dick. He clarified that
legislators will lay out terms of engagement for the contractor.
In other words, the legislature will essentially be saying that
this is the proposal the state is prepared to offer companies.
He agreed it is similar to pulling a lever. He highlighted that
the legislature must make a decision on how competitive the
state's fiscal system is compared to those in other
jurisdictions. The complication is that Alaska has more than
one type of asset and one lever. It would be a straightforward
exercise if it did. Therefore, the current challenge is more
complicated since there are different asset types and different
timeframes, which add dimensions that go beyond the one-lever
pull. He predicted the action would be the same, but "you need
more hands than the one you had up." He anticipated the
modeling work will bring some insight to the decision-making
process. He emphasized the best outcome in the discussion would
be the sense that in the foreseeable future the contractor will
get a risk return reward that is competitive and the government
is stewarding its resources on behalf of the people in the most
efficient way as it possibly can. He was unsure of the
variables and whether it would be the realities of fluid motion
through rock formation or it would be that Iran decided the
Straits of Hormuz would be just fine as is.
REPRESENTATIVE GARDNER asked what forthcoming information would
be included in future presentations from PFC Energy.
6:00:17 PM
REPRESENTATIVE MIKE HAWKER, speaking as the chair of the
Legislative Budget and Audit Committee, explained that during
the past summer the committee issued contracts with Pedro van
Meurs and others. Various committee chairs indicated the
legislature would need professional consulting advice with an
international perspective. He worked with the Legislative
Budget and Audit Committee's Vice Chair Stedman to identify PFC
Energy as a company with premier qualifications, and they
requested to engage PFC Energy specifically for the Legislative
Budget and Audit Committee, but also on behalf of the
legislature. Subsequently, PFC energy has been engaged in a
five-point work plan to prepare the state's fiscal model to
allow the committee to evaluate different proposals to come
before the legislature However, that kind of modeling must
evolve over the course of an engagement, since various
committees may want to try a new/different mechanism. He
highlighted that PFC Energy's contract calls for an evolving
model, but one designed in a manner and presented in an open and
transparent manner. He noted the commitment with PFC Energy
required vetting. Further, PFC Energy was instructed to discuss
their model with other modelers, such as ones in the state's
Department of Administration and Department of Revenue. He
explained the idea is to ensure that arguments don't surround
the model. He surmised this question arose from the
misinterpretation that Commissioner Butcher made in the Senate
Finance Committee, which gave the impression that the Department
of Revenue is using PFC's modeling, which is absolutely false.
He emphasized that PFC Energy continues to work solely on behalf
of the legislature through the Legislative Budget and Audit
Committee.
REPRESENTATIVE GARDNER thanked him for his thoughtful response.
6:04:07 PM
The committee took an at-ease from 6:04 p.m. to 6:15 p.m.
6:15:05 PM
[HB 3001 was held over.]
6:16:56 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 6:16 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES PFC PResentation 4.21.12.pdf |
HRES 4/21/2012 2:00:00 PM |
|
| Change_COP_Slide.pptx |
HRES 4/21/2012 2:00:00 PM |
HB3001 |