Legislature(2009 - 2010)SENATE FINANCE 532
03/26/2009 02:30 PM Senate RESOURCES
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| Presentations: Natural Gas Fiscal Designs | |
| Adjourn |
* first hearing in first committee of referral
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+ teleconferenced
= bill was previously heard/scheduled
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ALASKA STATE LEGISLATURE
JOINT MEETING
SENATE RESOURCES STANDING COMMITTEE
SENATE FINANCE COMMITTEE
March 26, 2009
2:39 p.m.
MEMBERS PRESENT
SENATE RESOURCES
Senator Lesil McGuire, Co-Chair
Senator Bill Wielechowski, Co-Chair
Senator Charlie Huggins, Vice Chair
Senator Hollis French
Senator Bert Stedman
Senator Gary Stevens
Senator Thomas Wagoner
SENATE FINANCE
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Charlie Huggins
Senator Joe Thomas
MEMBERS ABSENT
SENATE RESOURCES
All members present
SENATE FINANCE
Senator Johnny Ellis
Senator Donald Olson
COMMITTEE CALENDAR
Presentations: Natural Gas Fiscal Designs
David Wood, David Wood and Associates
Dan Dickinson, CPA
PREVIOUS COMMITTEE ACTION
No previous action to report.
WITNESS REGISTER
DR. DAVID WOOD, Consultant
David Wood and Associates
United Kingdom (UK
POSITION STATEMENT: Discussed natural gas fiscal designs.
DAN DICKINSON, CPA
POSITION STATEMENT: Discussed natural gas fiscal designs.
ACTION NARRATIVE
2:39:51 PM
CO-CHAIR BERT STEDMAN called the joint meeting of the Senate
Resources Standing Committee and the Senate Finance Committee to
order at 2:39 p.m. Present at the call to order were Senators
McGuire, Wielechowski, French, Wagoner, Huggins, Stedman,
Hoffman, Stevens, and Thomas.
^Presentations: Natural Gas Fiscal Designs
2:40:58 PM
CO-CHAIR STEDMAN announced the first presentation would be from
Dr. David Wood on natural gas fiscal designs.
2:42:10 PM
DR. DAVID WOOD, Consultant, David Wood and Associates, United
Kingdom (UK), said he had worked extensively on international
gas and fiscal issues and his report is an eight-month study
completed in December last year. His intention is to present
highlights of that report and discuss some of the developments
and issues that have arisen since the first presentation in
December.
He said the aim of the report was to look at Alaska's natural
gas fiscal regime and to compare it to other gas regimes around
the world. The other parts of the report evaluated the
components of Alaska's natural gas fiscal regime by looking at
how it performs for 10 natural gas fields - both non-associated
and associated gas fields. The mandate for this report was not
to look at a gas line or existing fields in terms of those
currently producing, but to look at a range of possible fields
that could be developed in the future; the study is a series of
hypothetical fields. It was necessary to build a fiscal model
with a multi-year cash flow analysis to look at the economic
performance both in terms of the fields involved and to analyze
in detail the different elements of the fiscal system.
2:45:51 PM
SENATOR WIELECHOWSKI asked for more information about his
background and if his typical clients are industry or
government.
MR. WOOD responded that he is a geologist and worked in the
1980s for Phillips Petroleum, Amoco and a number of independent
Canadian and UK companies. Much of his career in industry was
conducted in South America, the Middle and the Far East. He is
also trained in petroleum economics. For the last 10 years he
has worked as an independent consultant focusing primarily on
international gas and fiscal terms. He is published widely on
fiscal analysis of both oil and gas. The clients he works for
vary from oil and gas operating companies, but also governments
and he does training for companies. He doesn't represent this
issue from the perspective of a producing oil and gas company or
from a government's perspective. He is trying to look at it from
both perspectives, and he is used to doing that in the course of
his work.
2:48:23 PM
MR. WOOD said his presentation is an analysis of more than 20
major gas producers and he will use five or six of those to
illustrate the complexity and diversity of fiscal designs,
specifically those elements that can be considered as regressive
and progressive, around the world. Those countries are planning
to deliver gas into North America and the fiscal systems that
they operate will influence the cost of gas supply into the
Lower 48 states. That gas will compete with Alaska gas.
He said he will also discuss the multi-year cash flow model and
address the issues of fiscal instability, credibility, and
fiscal certainty that are very important in terms of getting
long-term off-take agreements with gas producing nations. As
part of the conclusions and recommendations he would identify
some of the issues that could be improved upon by further work
in understanding the gas fiscal design in Alaska.
2:51:16 PM
MR. WOOD said fiscal designs are best driven by clear fiscal
strategies and objectives. He showed a diagram with three key
objectives: sovereign take, local focus/jobs, and investment.
SENATOR FRENCH asked what local content focus means.
MR. WOOD answered that "local content" means involvement with
local companies or "local hire." His diagram showed where
different countries prioritize their objectives. North America
is very much focused on encouraging investment and work
programs. Many of the OPEC countries focus very much on
maximizing the sovereign take; other countries prioritize local
content. Norway stands out in that regard for many decades.
2:55:01 PM
MR. WOOD said Alaska gas needs to get to the Lower 48 market by
whatever means it can. In 2007, large amounts of gas were
imported into the Lower 48 from Canada, as well as large amounts
of LNG from a range of countries - at the point his diagram was
created Trinidad and Tobago supplied 60 percent of the imports
into the Lower 48. For obvious reasons that is one of the
closest of the countries able to supply LNG.
He said the orange dots and yellow squares indicate the LNG
regasification terminals, most of which are located on the East
and Gulf Coasts. In the last year the Costa Azul terminal in
Northern Mexico received LNG from across the Pacific and it will
soon receive it from the Sakhalin project in eastern Russia, but
also potentially from Australia and Indonesia and a wide range
of other countries. The cost of LNG is dependent on the cost
structure of the developments, but it is also influenced by the
fiscal designs that each of those countries has in place.
2:57:46 PM
SENATOR HUGGINS said that Dr. Myers' overview yesterday
described that presently, because of the cost of gas in the U.S.
that Europe and the Pacific Rim are more attractive to LNG
producers; so not much will be coming into the Lower 48 in the
near future. "Could you help us out with that?"
MR. WOOD said that is a good point. The justification for
building all the capacity for LNG receiving terminals didn't
envision gas at less than $5/mmbtu. At the moment, the volumes
coming into the U.S. are much lower than they have been, but
most in the industry believe that is a relatively short term
situation.
The next slide showed a huge amount of gas coming from domestic
production - conventional gas and large volumes of deep water
gas from the Gulf of Mexico. He remarked that Dr. Myers also
mentioned unconventional gas - deep tight gas, coal bed methane,
and shale gas - playing significant contributions. Even with all
that, there is still a requirement for more gas and forecasts of
demand increasing. There is an expected roll for LNG, he said,
with small amounts from Norway and potentially larger ones from
the field north of Russia, when it is developed, but
particularly from North Africa and the Middle East. Qatar
Petroleum and Exxon Mobil are planning to move LNG long
distances into both Europe and North America. Large projects in
West Africa - Nigeria, Equatorial Guinea already - and Angola
are under development. The major companies - ExxonMobil, Shell,
BP and others - are all heavily investing in these projects - in
many cases tens of billions of dollars - and moving large
reserves of gas - not all destined for North America, but other
markets in Europe and Asia. Clearly, they will be competing
sources of gas into North America.
3:01:26 PM
MR. WOOD said Australia, Indonesia, Papua New Guinea, Peru,
Qatar and Sakhalin projects involving major oil and gas company
investments have the North American market as part of their long
term development plan. It is important to recognize that there
will be competition from conventional and unconventional Lower
48 gas and from LNG coming from a wide range of sources around
the world. The cost of supply of that LNG is strongly influenced
by the fiscal designs of each of those countries. However, these
designs differ quite significantly and are "quite complex supply
chains."
One of the differences between moving gas by LNG and by pipeline
is that a pipeline moves gas from point "A" to point "B," but
one of the beauties of LNG technology is its flexibility in
being able to go to a wide range of destinations. Because of the
high cost, most LNG is actually contracted on long-term basis
take or pay contracts to two or three customers. But the
possibility of moving some of the LNG to other markets exists.
The main markets for LNG are East Asia (particularly Japan and
Korea), Europe, and North America. It is mostly indexed to oil
prices, particularly into Japan, and in Europe it may be related
to oil products if not directly.
In 2007/08, nuclear plants went down in Japan; it had a
shortfall of LNG and was prepared to pay in excess of $20/mmbtu
for short term cargoes of it. This is significant because for
that period of time, those producers that were able to divert
their cargoes diverted to Japan because they could double their
value. That meant there was less gas coming to the U.S. and
Europe for almost a year.
This flexibility comes at a price; it's less reliable because if
someone else in the world is prepared to pay a higher price,
that LNG will, if contractually possible, be diverted to that
location. This flexibility makes it less reliable.
3:05:09 PM
MR. WOOD said the last year has seen dramatic changes in demand
and prices. Slide 9 should be labeled "Natural Gas Imports to
the U.S." and over a decade the numbers rise progressively with
a lot of spread particularly in 2001/02. In 2008, for the first
time the volumes of gas imports fall. It is not related just to
the economic downturn, but to the increase of unconventional gas
production, particularly shale gas - particularly during 2007,
and the increase of domestic gas production.
Slide 10 shows an excess of 2 bcf/day of LNG being imported into
the U.S. in 2006/07, but it was fairly flat, about 1 bcf/day in
2008 and is remaining that way. The drop is due largely to the
increase production from unconventional Lower 48 gas. But more
recently it has been influenced by the economic downturn.
3:08:05 PM
MR. WOOD said another influencing factor was that most LNG
producers, particularly in the January to April 2008 period,
were more enthusiastic about selling their gas to Japan at
$20/mmbtu than selling it into the U.S. So a number of factors
are at play, but the overriding one is the increase in domestic
gas production.
SENATOR FRENCH asked the average daily natural gas consumption
in the United States.
MR. WOOD replied that the 2 bcf/day amounts to about 5 percent
of total consumption. Two different slides show how imports have
changed in 2008, and going forward how they are dominated by gas
from Canada until 2030 when it then significantly declines,
along with a significant increase in the amount of gas forecast
from LNG, but more than trickling in in the post-2020 period.
So, there is the expectation for a significant amount of LNG to
fill that imports requirement.
Gas from Mexico is gradually declining. The net imports
represent a relatively small component of U.S. gas consumption,
but the December forecast indicates net imports declining quite
significantly from 2010 through 2030. The main reason for the
decline is the massive increase in expected volumes from
unconventional gas. Alaskan gas begins to play a much more
significant role by 2030 than the net imports. But clearly in
terms of volume comparisons, Alaska will be competing with the
net imports of which LNG is going to be a big component.
3:12:47 PM
SENATOR FRENCH asked if Alaska is using 22-23 tcf/annually.
MR. WOOD answered yes, and the slide indicates that LNG is less
than 1 tcf/annually. The economic downturn is impacting
internationally traded LNG. The expectation is that the LNG
market will be oversupplied for two or three years and that will
impact world gas prices and influence commitments to develop new
LNG projects. This delays investment in new capacity, and that
means as demand increases less capacity will be available; so in
the longer term, 2015-2020, we might have another marked gas
price increase. So, expectations for the next decade probably
are oversupply going to a shortfall, and that suggests that
we're in for a period of volatile gas prices.
3:15:46 PM
SENATOR WIELECHOWSKI asked if his graphs take potential cap and
trade or carbon tax legislation into consideration.
MR. WOOD replied that these particular ones have not, but cap
and trade legislation should benefit gas, because of being the
least carbon emitter of the fossil fuels. It is competing
internationally in most cases against coal for power generation,
and the cap and trade mechanisms will penalize coal in
preference for gas - unless carbon sequestration technology
enables coal to continue at current levels. So, most cap and
trade scenarios would suggest that gas demand globally should
increase rather than decrease in this period of time.
3:17:07 PM
MR. WOOD said North America is competing with other regions to
secure supply of LNG. Historical data indicates the big markets
for gas imports in Europe have experienced significant growth in
the last 20 years and expectations are that it will continue to
grow at similar rates because the indigenous gas supply is
declining.
OECD Pacific includes Australia, Japan, Korea and Taiwan. So in
that group they have an LNG producer (Australia) and big LNG
consumers (Japan and Korea). They also have increased their
demand for imported natural gas over the past two decades, but
with massive investment going into Australia, the expectations
are that the net import position for LNG will not grow as fast
for that particular region.
The 2020-30 forecast indicates natural gas imports into North
America are going to grow rapidly, but still in comparison with
Europe and OECD Pacific until 2030 they are much smaller in
overall volume.
China and India start from very low current import volumes, and
expectations are that their demand for LNG will grow
significantly. So, the LNG sector has competition from these
areas, and delaying investments in the large LNG projects during
that shortage of supply in the 2020/30 period is going to mean
it won't be so easy for North America to secure that LNG should
it want to at that particular time. That gives Alaskan gas some
competitive advantages in trading into the North American market
in the 2020/30 period.
3:20:21 PM
MR. WOOD said to illustrate what is happening at the moment in
the international gas liquifaction sector, several new projects
are just about ready to come on stream or have already. But over
the next three years large capacities are in advanced stages of
construction in various parts of the world - in Qatar, Sakhalin,
Indonesia, and Yemen. A fifth train off the Northwest shelf of
Australia came on stream at the end of 2008 and it is ramping up
to full capacity. Other projects in Algeria, Angola, Nigeria,
and Peru are under construction and due to come on stream in
2011. Almost half of the 99.5 mm/tons of capacity coming on
stream during the 2009/12 period is coming from Qatar, which
will become even more significant in terms of its contribution
to worldwide LNG capacity.
Beyond 2013, a large number of projects are at the stage where
investment decisions are about to be made. Of course, with the
current economic situation investment decisions on many of these
projects is now under question. They may well be delayed and
it's this delay for the projects listed on the right of slide 14
that could lead to a shortfall in energy capacity and potential
price increases going forwards.
MR. WOOD said he hoped he had convinced them that LNG is going
to compete with Alaska gas for the additional capacity, and
consequently, LNG from almost all of these countries will have
cost of supply issues that will be influenced by their set of
fiscal designs. So understanding how these countries tax and put
their fiscal designs together is a worthwhile exercise.
3:23:46 PM
MR. WOOD said his reports outlines a number of countries and
structures. In overview terms, petroleum fiscal designs are
divided into two main generic types of structures - mineral
interest concessionary systems with terms of tax and royalty.
This is the North American system and the system in Alaska and
many other OECD countries. They have leases, licenses and fiscal
mechanisms that are driven by royalties and taxes. The other
structure is contractual terms.
The contractual systems (as opposed to lease and license
systems) and production sharing agreements (PSA) and productions
sharing contracts (PSC) are very much the dominant type of
alternative. Service contracts and hybrid contracts are in
between. PSAs originated in Indonesia in the 1960s and very much
from the concerns of the producing nations over their title to
reserves. Under PSAs, the producers at no time have title to
reserves and gain their share of revenues from production.
On the other hand, in the mineral interest systems, the
producers gain title to lease arrangements and hydrocarbon laws
to the reserves as they are produced. Some of countries use
PSAs, some use mineral interest agreements and some are using
both. The world has a wide diversity of operating fiscal
systems.
3:26:22 PM
MR. WOOD said his report has detail regions (with stars) that
already have major gas developments and very large reserves, and
a few are included because of the novelty of the fiscal designs
that are relevant to gas systems.
He said he selected six countries from the list to review fiscal
design structure. They are countries that can potentially supply
LNG into North America and are where the major oil and gas
companies have or are about to invest tens of billions of
dollars into developments. These fiscal designs are of
especially of interest because they are designs that oil and gas
companies can live with.
3:28:49 PM
MR. WOOD said Algeria operates both mineral interest structures
and PSAs. A new hydrocarbon law introduced in 2005 toughened its
fiscal take; it has multi-layers of tax both on revenues
(gross), income (net), and an extraordinary income windfall tax
on oil, which is effectively a sliding scale tax. It has an
agency dedicated to monitoring gas contracts so they have
minimum take or pay inclusions that are signed. One of the
significant points is that state equity participation is 51
percent. He said state participation is a key feature in many
countries.
SENATOR FRENCH asked if Algeria when it changed its tax in 2005
prohibited itself from making future tax adjustments.
3:30:57 PM
MR. WOOD replied that he understands that they didn't lock it in
and are open to making further changes if they wish to.
SENATOR FRENCH asked him to let them know if they do.
CO-CHAIR STEDMAN asked him to let the committee know about
changes by all the countries he is covering.
MR. WOOD said the report generally mentions stability clauses,
which are more likely to be in PSAs.
SENATOR FRENCH reminded him that Alaska is under a tax and
royalty regime.
MR. WOOD noted that most tax royalty regimes usually don't have
a commitment to not change tax in the future. The issue very
often is if they are going to be retrospective in terms of
impacting licenses and leases that have already been given out.
3:32:23 PM
MR. WOOD moved on to Angola (slide 19), which has a production
sharing fiscal system. For contrast, Algeria has large onshore
non-associated gas fields and gas condensate fields. In Angola,
much of the industry development is associated with deepwater
oil fields with associated gas. There are large volumes of
associated gas, but the primary reserves and the primary field
developments are associated with oil.
Alaska has associated gas with oil and it is located in deep
water; so the issues of developing that gas are quite different
from developing the onshore gas in Algeria. Of course, the
context of where the gas is located, whether it's associated or
non-associated, whether it has natural gas liquids and
condensate with it or not, will also have a bearing on the
fiscal design. A key part Angola's fiscal design is the
involvement of large signature bonuses associated with licensing
rounds equivalent to the lease sales that will occur in North
America, but these are competitive bidding rounds and some of
the signature bonuses paid for large areas have reached almost
one billion dollars for some of the more prospective licenses.
Some of the companies bidding at those levels, not just the
major international oil companies, but also the national oil
companies - Petro-China, and the semi-privatized national oil
companies like ENI - have bid multi-hundred million dollar
signature bonuses as part of acquiring the rights to drill and
develop in these areas. So, from the government's perspective,
the very high upfront revenue from the signature bonuses is a
significant component of their fiscal system and it's a low risk
part of that design.
MR. WOOD said Angola has the large signature bonus component,
cost recovery and uplift of capital costs. The key driving
mechanism for the profit sharing is a mechanism linked to rate
of return. The more profitable the project becomes the greater
the share of revenues that go to the state. In periods of very
high profitability, both the Algerian and the Angolan state take
is well in excess of 80 percent of the revenue stream.
Norway (slide 20) operates a mineral interest system, and has no
royalty or bonuses; all of its taxation components are very much
at the income or profitability end of the cash flow. They have a
corporate and special tax, and since 2004, investment uplifts
over a four-year period were introduced that provide shelter for
the smaller fields have been introduced against their special
tax. So, what is interesting here is that many large and small
companies have been attracted in recent years to sign licenses
with Norway being attracted particularly by the investment
uplift, which works a little bit like Alaska's investment
credits. It also has taxes on CO emissions.
2
3:38:01 PM
Norway's stated fiscal strategy is interesting in that they have
no fiscal stability clause and they have the right to change and
exercise that right to change their mechanisms from time to
time. But they have certainly convinced the industry of their
intention of being a "sleeping partner" with their role being to
keep projects commercially viable, but at the same time maximize
the position of the state. Marginal tax rates are a little short
of 80 percent, a relatively high take that is at the profitable
end.
Papua New Guinea (slide 21) has a mineral interest system; it is
a very isolated and relatively underdeveloped country, but it
has wrestled with the development of large gas reserves for the
past few decades. It spent maybe five years trying to get a
gasline from Papua New Guinea to Queensland and then shifted its
strategy to LNG; it is now in the feed stage of several LNG
projects, the largest one being with ExxonMobil. The final
investment decision on that is expected within the next year or
so. The fiscal mechanism has gone through legislation to ratify
and fix for a period of time. So, in this case there is a fiscal
stability associated with these particular terms. Again, he
said, the terms are small royalty, income tax, and additional
profits tax, which is driven by the rate of return generated by
the project and that additional profit tax goes up as the
project becomes more profitable.
3:40:52 PM
MR. WOOD said state equity participation is a feature of this
fiscal regime - 22.5 percent with 2 percent of that going to the
local landowners.
Qatar operates under PSAs; and Qatar Petroleum has 65 to 70
percent equity participation in its projects. Fifty percent of
the revenue allocation is for cost recovery, but the main profit
sharing component is linked to volume of production, and gas is
sold at a relatively low price from the field to the
liquifaction terminal. The liquifaction terminal pays a
corporate tax. The NGLs are taxed according to an "R factor"
that is the ratio of cumulative revenues to cumulative
expenditures. This is a fiscal feature used in many contracts
around the world to drive the profit sharing.
Trinidad (slide 23) is a major LNG supplier to the U.S. It runs
both a mineral interest system and a PSA system with sliding
scales of taxation in both and those are linked to price and
volume in the production sharing structure.
3:43:47 PM
The committee took an at ease at 3:43 p.m.
3:52:40 PM
The meeting was called back to order at 3:52 p.m.
MR. WOOD continued his presentation saying the report not only
takes into account the size of the reserves, fiscal designs and
structures, but risks and opportunities associated with
developing in the large resource areas as well. The positions of
various countries are linked to reserve size on the slide. Once
a gasline is developed, a higher opportunity of developing
additional resources would improve investment opportunities and
decisions. So, risk and opportunity is an important component.
The overall government take is easy to use to compare the
different fiscal systems, but each gas resource, the size of
that resource, the cost to develop it, and the prices that are
prevailing will influence the state take. However, in general,
he said, as prospectivity and reserve size increases, government
take typically increases as well. Certainly in the big gas
producing countries government takes in excess of 90 percent are
seen. On the other hand, in less developed countries the take is
lower.
3:54:44 PM
MR. WOOD mentioned that different fiscal elements can be
combined to optimize the government take. His diagram showed
that some of the project revenues from selling Alaskan gas are
used for development and operating costs; the profit component
that is left and the rent component is key to the fiscal
designs. The various instruments used can be classified as
regressive or progressive. Regressive means when the costs go up
and prices go down; a regressive tax often leads to a much
larger share of profits falling into the taxable portion. So
typically property taxes and royalties are regressive in nature,
but on the other hand those taxes that are levied on profits and
further through the cash flow system are more progressive in
nature.
Norway's fiscal design was very much focused on the progressive
end of this scale whereas other examples, like Egypt, have a
fiscal design based on production volumes and falls on the
regressive end. But generally, the two are mixed. He explained
that for governments it's much lower risk to have regressive
taxes. On the other hand, producers prefer to have progressive
taxation because it means that they pay taxes when the projects
are profitable, but none when they are not profitable.
3:57:25 PM
SENATOR FRENCH asked him to speak a little more about the need
to have a commercially attractive environment and what degree of
fiscal stability is needed. This has been one of the struggles
in coming to terms with the state's gas pipeline. AGIA offers
ten years worth. How much fiscal stability should Alaska offer
and to what degree are the requests for fiscal stability offered
up in the bargaining and then let go as an element of bargaining
between industry and governments?
MR. WOOD replied that is a very involved topic and question.
"Fiscal stability is clearly important." His view is if you have
a fiscal design that is flexible and has progressive elements
and also some regressive elements to provide security of base
level revenues, that design can significantly reduce the need
for a clause that guarantees that the fiscal regime won't
change. Because if it is structured such that it works over a
wide range of economic and production conditions, then the need
for a guaranteed statement of fiscal certainty falls away.
So, my view is that you're better to address it by
having a flexible fiscal design, but clearly in
certain circumstances, where we're talking about a
billion dollars in investment and tens of years before
returns on that investment are going to be achieved,
then it may be necessary to enter into clauses that
guarantee certainty for a period of time. If you do,
as a government, have to offer those guarantees, then
my view is that you have to be sure that your baseline
regressive elements are adequate to meet changing
conditions.
4:00:30 PM
SENATOR FRENCH asked whether he thinks in his professional
opinion that Alaska has such a system in place now in the ACES
legislation - as well as the royalty regressive elements.
CO-CHAIR STEDMAN interrupted to say that Mr. Wood had spent time
looking at 10 hypothetical fields and is in the process of
getting established with LB&A to look at Prudhoe, Kuparek and
Pt. Thomson, which will give him a better feel for
Alaska/Pacific issues. He clarified that this is the first step
in many steps and that Mr. Wood could answer that question in
any manner he is comfortable.
MR. WOOD responded that he sees the need for Alaska's tax regime
to be more flexible and to target incentives and allowances more
easily against the regressive elements in certain circumstances.
The issue of gas and oil being very tightly linked together in
that system reduces the flexibility.
4:02:09 PM
CO-CHAIR STEDMAN said LB&A would soon get a request for further
analyses by Dr. Wood with a preliminary discussion in late
summer early fall and a final report in the middle of November.
He repeated that this is early in the process.
MR. WOOD said his slide illustrates the difficulties with
regressive elements. Royalty can take a relatively small share
of the profit at low prices, but the same percentage royalty can
eat up a huge part of profit - the problem of regressive
elements for producing companies. Sometimes allowances and
incentives are needed to limit their downside impacts.
He showed a schematic of Alaska's prevailing fiscal design that
he had worked on with Dan Dickinson to try and illustrate the
different levels of taxation in Alaska to highlight the fact of
several layers of taxation that are calculated on different tax
bases: property taxes, royalty that is calculated on a point of
production value (gross value) after an allowance for
transportation costs, production taxes that are calculated on a
production tax value base (net base), and a progressivity
component that comes into play at higher production tax values.
Making assumptions of $25/barrel of oil equivalent (BOE) in
costs would mean that the progressivity element would kick in at
around $55/BOE. In 2008 the progressivity element played a
significant role in raising revenues for Alaska. Then it has
Alaska corporate income tax and federal income tax on top of
that.
4:05:09 PM
MR. WOOD pointed out that like a number of other countries
Alaska has a number of layers of taxes calculated on different
bases; of these, the royalty, property taxes, and production tax
floor are the regressive elements. The investment credits, the
production taxes, the progressivity components are the
progressive elements.
MR. WOOD stated that the changes introduced into Alaska's design
in 2005 through 2008 have generally introduced levels of
progressivity, but because of the higher production tax rate of
25 percent, they have also increased the overall state take
which has made some of the smaller fields less commercial.
Part of the study was focused on the progressivity elements of
Alaska's fiscal design, particularly the combined progressivity
tax, because it combines the revenue streams of oil and gas and
calculates them on a BOE basis with a simple 6:1 gas to oil
ratio. Much of the report looks at how that progressivity tax is
currently structured and how it might be modified by separating
the calculation for gas and oil.
4:07:10 PM
MR. WOOD said one of the problems the report illustrates is that
by having progressivity calculated on a combined basis, Alaska
can end up with a situation of having large production volumes
of gas when gas is at a relatively low price to oil -
effectively diluting the combined production tax value on a BOE
basis, thereby reducing the progressivity elements of the
taxation.
The progressivity tax trigger is difficult to set at a point
where it is effective for both gas and oil on a combined basis,
and he thought it would be easier to set progressivity if they
were separate. Also tying the production tax floor to the gross
level (the point of production value) can lead to some
complications to the way in which the production tax calculation
works.
The outcome for progressivity for natural gas can create a
dilution effect if the gas prices are low and oil prices are
high, but the relative volumes of oil and gas make a difference,
too, Mr. Wood said. On the North Slope, oil production will
decline and gas production will increase. So the issue of
varying prices and volumes will come into play with those two
products there. Reinvestment can reduce the liability for
progressivity quite significantly, but again that varies
depending on volumes and prices. His slides summarize the
analysis of how gas potentially dilutes the production tax and
progressivity values on a combined basis.
4:10:03 PM
SENATOR FRENCH said he didn't really understand the charts that
well and suggested getting both charts and a numerical printout
so they can see the net effect on the tax.
MR. WOOD agreed to do that and went on to explain that gas
production tax values below $20 BOE generally act as a diluting
effect. The other significant point qualitatively to get from
this diagram is that the lines aren't straight; the curve
relates to the structure of the progressivity tax, but it also
makes it quite difficult to exactly predict the influence. That
influence depends on the relative prices of oil and gas.
4:13:17 PM
MR. WOOD said the more that is reinvested, the more dilution is
involved. He said these diagrams are showing how difficult it is
for investor's to predict the outcomes of their investment. Will
producing more gas have a positive or negative effect on a
particular field? Having oil and gas combined together makes
some of these decisions quite difficult from both the state's
and the producers' position. He said the magnitude of the impact
will vary because of the price and volume differentials and the
amount reinvested.
4:15:43 PM
MR. WOOD said his report looks at the prevailing case of
combined progressivity tax and at nine other cases where the tax
is separated. He has shown many different mechanisms - a range
of possibilities - that could be used alternatively to calculate
that progressivity while not advocating for any one of them.
4:17:47 PM
MR. WOOD described his graphs saying that he used a multi-
scenario, multi-year cash flow model to carry out the analysis.
He looked at 10 hypothetical fields and carried out multi-year
fiscal performance on each of them. Five of the 10 fields look
at non associated gas fields ranging from .5 to 10 tcf of
reserves. The second half were all fields with associated gas
the largest of which was a .5 bb/oil and 700 bcf/associated gas.
Economic assumptions were the base case gas price of $7.5/mmbtu
in the first year of the analysis and $80/barrel for oil;
inflation assumptions were used.
A key point of this modeling is that it uses a base case, but it
uses very wide ranges of sensitivity analysis; so it looks at
prices down to very low levels and up to very high levels for
both gas and oil, along with costs and other economic factors.
4:20:41 PM
MR. WOOD said in summary, the base case shows that the world of
the oil field is quite different from the world of the gas field
in Alaskan terms. The government take of destination values
(gross) is about 60 percent for oil fields and 75 percent of the
net portion of the cash flow. For natural gas fields the
government take is just 30 percent of gross value and take of
the net is at 67 percent. So, in revenue terms the gas world is
taking half of the gross revenue stream compared to what is
taken by oil. The reason is that the transportation, tariff and
treatment costs for oil are much smaller at 20 percent than for
gas at 50 percent. This is why the government take is 60 percent
as opposed to 30 percent of total revenue.
He said it is important to realize that the world of gas is
quite different from the world of oil primarily because most of
the costs in the transportation element. That is another
argument for considering looking at gas and oil tax individually
rather than trying to combine them into one system.
The base case assumption for the gas example shows that
royalties and base production tax are the largest components of
taxation. On the other hand, for oil it's royalty, the base
production component and progressivity (a significant
component).
4:25:07 PM
MR. WOOD said he used $80/barrel as the base case oil price. If
he used $55/barrel the CPT would be non-existent. His pie
diagrams show that the contributions from the different fiscal
components are quite different for an oil field compared to a
gas field. The fiscal designs go far beyond the upstream issues,
and his mandate for this report was to focus very much on the
upstream issues, but integrating the gas field production with
the infrastructure - whether it be LNG or a pipeline - treating,
exporting and transporting that gas are also important
components.
He said it is interesting that the major companies in Nigeria,
Algeria, Russia, and Qatar have been very prepared to sign up
for big projects on the basis that the upstream and downstream
components of those projects are integrated and that there has
been some limitations on third-party access.
His large project scenarios last three or four or more decades;
the alignment between the organizations that are developing and
producing the assets together with the state entities that are
controlling them is very important. Fiscal design will get them
only part of the way to a successful project. These scenarios
will show the division of the profits, which is quite important
in terms of attracting investment into particular field
projects.
4:28:23 PM
SENATOR WIELECHOWSKI said Alaska has been accused of changing
its tax system too many times and creating an unstable fiscal
environment. He asked if Alaska changes its tax structure again
- to delink oil and gas - would that open it up to more
criticism.
MR. WOOD replied that while it is true the fiscal system has
been changed several times, and that has lead to criticism from
certain quarters, if you can clearly identify why the changes
are being made and that they are beneficial to the overall
structure and not purely designed as penalties - that the
overall structure is being changed to enable the tax to reflect
more accurately the production situation for gas - but also to
enable allowances and credits to be targeted specifically at the
gas or the fields trying to be developed - if changes can be
justified and identified with clear strategies in mind - that
overcomes the potential for criticism of instability.
4:30:28 PM
Conclusions and Recommendations of the preliminary study:
Regarding the progressivity tax structure: under the current
production tax rules the impact of gas revenue on the magnitude
of combined production taxes is difficult to predict making tax
planning difficult (for both state and producers). Because gas
and oil prices are volatile now, over time it is likely that
structure will become unstable. His conclusion on his work so
far is that there are clear benefits from separating the
taxation of oil and gas on a progressivity basis. It would make
sense to use North Slope fields as examples of what the impacts
of separating oil and gas taxation mechanisms would be. In the
longer term there may be opportunities to look at LNG and GTL
developments as alternatives to see what they do under different
fiscal structures and combine that with the hypothetical field
work that has been done already. It would also be informative to
compare Alaskan gas delivered into the Lower 48 with its regime
to gas delivered by shale gas producers based on their
particular fiscal designs.
MR. WOOD said that a number of approaches could be made to
improve performance and credibility of Alaska's fiscal design.
Frequent changes and instability can be overcome by having very
clear statements of the state's strategy and objective for its
fiscal design, by having a simple, flexible and progressive
fiscal design that is easy to predict, and having some levels of
fiscal stability guaranteed. However, flexibility is very
important. He said that focusing progressivity on gas and oil
separately can also be a significant improvement on the current
system.
4:35:35 PM
SENATOR WIELECHOWSKI said one of the concerns about delinking
oil and gas has been that it would create an accounting
nightmare for the administration to try to monitor expenses. He
asked if other countries have had trouble with that and if they
had effectively dealt with it.
MR. WOOD replied that the industry is used to separating costs
for oil and gas in many areas of the world. It can be done many
ways, but the simpler the better. Industry could do allocations
based on volumes or values, but the accounting doesn't have to a
nightmare.
SENATOR WIELECHOWSKI asked if most countries that have similar
types of fields with intermingled oil and gas, like Alaska has,
have their oil and gas taxes delinked.
MR. WOOD replied that many do. They do it because of the very
reasons he discussed - because the gas is going through a
different supply change with a whole series of different cost
structures and elements and sold into quite different markets.
By not separating them out it is very difficult for the fiscal
system to work on a combined basis.
4:38:13 PM
DAN DICKINSON, CPA, said he and Rich Ruggerio, Gaffney Cline,
have both presented analyses on this issue over the last year.
The dialogue has really focused in on a single example that was
presented from Dr. Wood's work that has taken on a life of its
own. It is just one example, and it is a situation in which the
oil price boomed (in 2008), and at the same time the gasline
came on stream. Because that gas is added, total state revenues
do not increase, but decrease, particularly in this one example
that just deals with the production tax.
SENATOR FRENCH asked where his model could be found.
MR. DICKINSON said he believes it is on the LB&A website.
Assuming oil production is half of what it is today at 350,000
barrels/day (this is also assuming it is 10-15 years in the
future when a gasline might actually be coming on stream), 128
mm/barrels/yr. of oil are produced (progressivity is calculated
on the 128 mm/barrels/yr.). The next cell set the price of oil
at $135/barrel (close to the highest price). From that the
combined average costs to get it off the North Slope and to the
West Coast were subtracted - about $6/barrel. That leaves a
gross value at the point of production of $129/barrel.
You then have to account for a royalty share, which leaves
approximately 87.5 percent (the taxable wellhead). This amounts
to about $14 billion. In this example he assumed $3 billion in
costs to run the North Slope fields and that gets subtracted
from the taxable value (net) and that is about $11 billion. Now
the progressivity gets calculated. If the oil is stand-alone,
you divide the taxable value by the taxable volumes, which in
this case this results in $99/barrel. Under progressivity $30 of
that is sheltered; so you come up with $69.48, and then .4
percent on the first $62.50 is taxed for every dollar; above
that it's .1 percent for every dollar. In this example the
progressivity charges add 25.7 percent. He explained that the
base tax rate is 25 percent, another 25 percent is added because
of progressivity; so the total tax rate is about 50 percent. If
you multiply 50 percent times the tax base ($11 billion), you
come up with about $5.5 billion.
Now looking at gas in the example; it's producing 4.2 bcf/day (a
figure people talk about being the size of the pipeline) at
365/day/yr.; that comes to 1,500 bcf/yr. Current law says the
way combined progressivity is calculated you take all the gas
and convert it to barrels of oil as if there were 6,000 cf/gas
generated by one barrel of oil. That is called thermal parity
because if you burn that much oil, that is about right. In this
example, you end up with 255.5 billion barrel equivalents of oil
from the gas. That results in a 2:1 ratio.
But assume there is just stand-alone gas. You would look at how
much it is selling for. He chose $6 gas as a way to illustrate
an extreme point. The price of gas would probably be higher if
oil was $135. So, he assumed a 75 cent adjustment from Alberta
to Lower 48 markets, a $2.75 transportation charge to get the
gas from the North Slope to that point, and so there is a gross
value at the point of production of about $2.50. You multiply
that times the volumes and come up with a $3 billion charge. So
he explained, at this level there is no progressivity on the
gas; in other words it doesn't escape "the $30/barrel equivalent
of oil collar." If the gas were generated alone, it would
generate about $800 million in tax.
But the critical issue is what happens when the two are
combined. If gas is contributing about two-thirds and the oil is
contributing about one-third. The taxable value line shows that
the oil is contributing about $11 billion and the gas is
contributing about $3.5 billion. So the ratio is reversed to 3:1
with gas being the 1. Divide that by the taxable equivalents and
you come out with a barrel of oil equivalent of $43 for
(combined) purposes of progressivity.
So the oil stand-alone is $99; the gas expressed on a similar
basis is $15 and combined $43/barrel. Subtract the $30 trigger
and you come up with $13.16. That generates about 5 percent
progressivity instead of 25 percent, a huge drop in
progressivity. You add the 5 percent to the base rate of 25
percent and come up with a 30 percent combined rate instead of
50 percent rate. Because that rate is so much lower, in effect,
the amount of tax generated (because of the drop in
progressivity) is smaller with the gas.
4:49:00 PM
MR. DICKINSON said he and Mr. Ruggerio had both discussed this
example and it is important for members to know that they are
both looking at the same glass of water and one of them is
saying it's half full and the other saying it's half empty. They
both agree it could happen. The more oil you have, the more
pronounced this effect is. Mr. Ruggerio had pointed out that the
price spike had only happened 7 months out of the 14 prior
years.
MR. DICKINSON observed that the adopted and passed legislation
has special language that says what progressivity is going to be
and that it would "bend over" when production tax value is at
$92. If you add costs to that, that means oil prices are at
$115. When people wrote that legislation, that number was
"nuts." No one thought oil would everbe that high. Prices have
gone above that 3 times in past 14 years and they all happened
this summer. The point is that some of these things are rare,
but it's worth making sure you are dealing with rare situations.
MR. DICKINSON went back to 1995 when there was a huge gap in oil
and gas prices. But who cares, because in March 1995, gas was
selling for $1.50 at the Henry Hub and oil was $17. That would
have nothing to do with the world of progressivity. He is
focused on what happened in the last 6 months of FY/08. His
graphic was of January 1994 through the end of 2008. The blue
line represented the ANS price; the purple line (gas) takes the
Henry Hub price and multiplies it times 6 for thermal parity.
From 1994 through 2006, when this rule was made law, it looked
good; fundamentally the two kind of moved around each other. But
something happened in 2006, and from then on, oil has sold at a
huge premium over gas. Interestingly, the lines come back to the
6:1 ratio in January 2009. His point is that you can have
extreme situations in the current tax system, but that didn't
mean it was unstable.
He said they both agree that a single month or a one-year
snapshot only tells part of the story, particularly if you are
dealing with progressivity. So, he did include a month snapshot;
and where his annual one showed a loss of $1.2 billion, the
single month one showed a loss of $100 million (oil and gas).
But you wouldn't expect that to be maintained over a year.
4:53:11 PM
MR. DICKINSON said the main place he disagrees with Mr. Ruggerio
is the question of whether further investigation of a distinct
gas tax is warranted. If the main issue is the cross subsidy
between oil and gas and what happens in progressivity at high
prices, the solution is simple. You simply calculate oil and gas
progressivity distinctly, using the exact same rules. So, if
there is no progressivity in gas, the story ends there. Then you
calculate the progressivity on oil, but you don't take the gas
at its lower value and make it part of the oil calculation.
The second bullet point on cost structures were done when people
were thinking about oil, and then moving the gas to the 6:1
ratio. When you lose that ratio or if you look at the actual
markets that gas are being sold and transported into, you "have
to scratch your head about whether the structure is appropriate
for both."
His last point was, if the main issue is competitiveness,
government take and how that fits into the overall cost
structure, then you may need to look at other aspects of the gas
tax. But he thought creating separate taxes for oil and gas
would require fairly narrow changes.
MR. DICKINSON reiterated that Transcanada and ConocoPhillips
both made the point that they think there is additional work
that could be done on taxes but before they get to an open
season structure.
4:56:32 PM
CO-CHAIR STEDMAN thanked everyone for their testimony and
adjourned the meeting at 4:56.
| Document Name | Date/Time | Subjects |
|---|---|---|
| DWAlaskaFiscalDesignGas - 03-26-09.ppt |
SRES 3/26/2009 2:30:00 PM |
|
| Dickinson - 03-26-09.ppt |
SRES 3/26/2009 2:30:00 PM |