Legislature(2013 - 2014)BUTROVICH 205
02/14/2014 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB138 | |
| SJR5 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 138 | TELECONFERENCED | |
| *+ | SJR 5 | TELECONFERENCED | |
| + | TELECONFERENCED |
SB 138-GAS PIPELINE; AGDC; OIL & GAS PROD. TAX
3:32:56 PM
CHAIR GIESSEL announced that the first order of business would
be SB 138.
JANAK MAYER, Partner, Enalytica, Anchorage, Alaska, presented
information on the "Gas Pipeline: AGDC; Oil & Gas; Production
Tax." He shared his work history working on oil and gas issues,
oil tax reform, and transition to gas issues. He lead the
Enalytica's team at PFC Energy focused on upstream economic and
financial evaluation, constructing economic and financial models
of projects, assets, transactions, portfolios for large
international companies to small independent players to private
equity firms.
NIKOS TSAFOS, Partner, Enalytica, said his chief responsibility
was heading the global gas consulting practice of the firm and
that he had worked with some of the world's largest oil and gas
companies on a number of themes: helping companies that have gas
figure out how to sell it, helping companies that want gas
figure out how to buy it, and helping companies try to make
sense of what is happening in the market and thinking through
possibilities and scenarios. His core expertise is natural gas,
natural gas markets, and commercialization strategies.
3:35:17 PM
MR. TSAFOS began with a focus on the need for alignment in
making the decisions embodied in SB 138. He said it was
complicated, but he would try to explain LNG in terms of oil.
The Department of Revenue's (DOR) fall 2013 Revenue Sources Book
forecasted the value of oil for FY2015 to be about $105/barrel,
minus $20 for the mid-stream and $46 for the deductible lease
expenditures; that ends up being worth $49 at the well head on
the North Slope (slide 4).
3:38:41 PM
MR. TSAFOS said the price of gas isn't quite as clear as the
price of oil; it's less transparent, because you can't really
pick up the Wall Street Journal to see what the LNG price is.
It's not consistent and it is variable by destination and
contract. He explained the same project could be selling gas to
five different people at five very different prices. The price
of gas is likely to be linked to oil and likely to be linked to
the Japan Customs Cleared price (JCC) or what is known as the
Japanese Crude Cocktail. It's effectively the price that Japan
pays for its oil and that trades at a 22 cent discount to ANS.
So, for all intents and purposes, if the state sells LNG that is
linked to the price of JCC, it is linked to the price of ANS.
Lastly, Mr. Tsafos said, in general, gas trades at a thermal
discount to oil. So, a $100-barrel of oil does not lead one to a
$100-BOE. There are a number of reasons for that, the chief one
being, especially in targeting the Asian market, there are still
consumers that would switch to oil if LNG were higher (by
declining to buy a cargo of LNG because oil is cheaper). So, in
some ways, oil places a little bit of a cap on the price of gas.
SENATOR MICCICHE asked for an explanation of BOE.
3:41:59 PM
MR. TSAFOS explained that BOE means barrel of oil equivalent and
it tries to get to the question of how much energy different
fuel agents - oil, gas, coal - have. This conversion process
tries to turn gas into having the same energy as oil, so in
theory a barrel of oil and a BOE should contain the same amount
of energy.
He explained that there are two main differences between oil and
gas in the midstream, however; gas is more expensive to
transport than oil and the tariff is not going to be regulated
by FERC. Its price will be very much driven by not just the cost
but also how the expected return on the investment is
structured.
Slide 7 assumed a FY15 forecast of almost 500,000 barrels of oil
(bbl) and about 400,000 BOE at $100 bbl/$81 BOE; the midstream
is $10 bbl/$66 BOE.
3:45:07 PM
Upstream oil is about $6 and about $9 BOE at the wellhead. So,
if you're trying to tax at the wellhead, you're kind of ignoring
the largest part of the BOE, which is midstream. Slide 8
indicated how a drop in ANS at $90 can wipe out that $9 BOE, and
at that point you basically have no value up on the North Slope
to tax. In a different way, slide 9 hiked the costs or tariffs,
not an extreme assumption, but that still ends up as zero.
Slide 10 brought it all together and allowed conclusions to be
formulated. The big picture is you want to get a fair value for
your gas, but how the midstream is structured is a huge driver:
envision the litigation surrounding $10/barrel midstream and
then what it would be for $66/BOE midstream! Upstream is
important but in the grand scheme of things it really pales
compared to the midstream; 35 percent of 384,000 annual
production at $81/BOE would result in a state take of $370
million, not a very big number.
3:49:03 PM
MR. MAYER showed an analysis of $80 BOE with $10 (roughly what
one might expect as a sale price into Asia in a $100 ANS West
Coast world) attempting to illustrate that returns to the
upstream, royalty, and production tax vary wildly if those are
the principle sources of revenue for Alaska. He said one can see
the potential benefits from equity participation and taking RIK,
but that gives a lot of exposure to local gas prices. Basically,
whatever the state does, it is exposed to risk from quantity
prices and royalty, and taking RIV actually poses the greatest
price risk to the state, because of its amplifying mechanism.
The reason being the construct of the fixed tariff, which in the
oil world is a very small portion of the overall BOE, but it is
such a large portion in the LNG world that it's like the state
guaranteeing a particular rate of return and taking a share of
what is left over. If that fixed portion takes up the vast
majority of the BOE, what is left varies wildly with very small
changes in prices. So, a 10 percent drop in price can mean the
difference between still substantial revenue and tax take versus
none at all.
3:52:53 PM
SENATOR FRENCH said the RIV should be fixed at the state's
royalty rate of 12.5 percent, so he was assuming the blue box
would be steady all the way down, but instead it was shrinking.
MR. MAYER said the point is that it's not 12 percent of $100 or
$110 in value; it's 12 percent of $110 minus the tariff. That is
the reason in talking about alignment that the tariff becomes
critical. Small changes in capital structure and rates of return
that set that tariff can suddenly take away the vast amounts of
the share of value for the state. Price movements can also erode
the value to the state entirely. The counterintuitive point is
that in lots of ways gas, both RIK and tax in kind, with a
corresponding equity share offers more rather than less downside
protection for the state, and the state in this environment
actually takes a little less on the upside. There is potential
upside to the state in a high price environment from the RIV but
more downside as well.
He said his analysis, unlike the previous analysis, was of
actual results from Enalytica's model of an AKLNG project over a
30-year timeframe, but using general terms like low, mid, and
high prices rather than specific price points. It shows a world
in which the state takes (and the HOA sets out) a range of 20 to
25 percent share of gas and a corresponding equity stake
throughout the value chain. While some of the assumptions need
to be refined, the questions are the same: at relative price
movements where value to the state is at high and low prices.
The analysis showed that the return to the state was greatest
for taking RIK when prices are low but that in return the state
gave up a little when the prices were high.
3:57:39 PM
SENATOR FRENCH asked why the crossover point was at a different
price for the producers than it was for the state. He thought it
would be a mirror image.
MR. MAYER said there are more variables at play than just what
the state and producers receive: the other stakeholders - like
the federal government and the debt holders in the project.
SENATOR FRENCH asked if TransCanada performs identically to the
state in this scenario.
MR. MAYER answered not necessarily, but this analysis didn't
detail TransCanada's participation; further, he said that
involving a separate third-party midstream player for any of the
state's share inherently brings some fixed tariff component back
into the equation - not the full $66, just the tariff on the
liquefaction and the pipeline, and if the state were to exercise
its 40 percent option the level under which it would be subject
to that fixed obligation would be reduced further.
MR. TSAFOS added another reason it is not identical is because
the state's share includes parts of the chain that TransCanada
is not a partner in: the LNG facility and the upstream. The
whole idea in slide 11 was that RIV makes the upstream the sole
price absorber and the fixed nature of tariff in "in value"
amplifies the impact of price movement on state returns.
4:00:39 PM
MR. MAYER said for this analysis he had both parties sell their
LNG for the same price, to help people understand what a change
in either direction would do for either party - all other things
being equal and RIK participation versus RIV. The state is more
insulated from price movements taking less of the downside with
less upside exposure and the producers, counter to that, have
greater price exposure through RIK than RIV. The federal
government also has more exposure to price changes in the RIV
world. By participating in the project the State of Alaska
becomes a non-taxpaying entity, as long as everything is
structured properly (if it owes any state taxes it owes them to
itself and can discount them) with the exclusion of property tax
which they had factored in as a state obligation.
So the project has two components: a producer component and a
state component. The producer component with revenues from the
sale of LNG, costs associated with building the upstream and
different midstream components, tax obligations, and then
netting all those out, an after-tax cash flow. The other
component, Alaska, has the revenues, the same cost components or
at least a 25 percent share of them (except for the upstream
cost), and no tax obligations. That means the state is better
off in low price environments and as the non-taxpaying entity
that means the federal government is worse off.
4:03:38 PM
MR. MAYER pointed out that just because the state has a 25
percent share in a project doesn't mean that it gets 25 percent
of the overall value (slide 13). In most circumstances the state
is actually taking substantially more than 25 percent and there
are a couple of reasons for that, which come back to federal
government take: while the state foots 25 percent of the bill
for the midstream components it doesn't foot any of the bills
for the upstream and it's also a tax exempt player in this
project. So the portion of value it gets out of its 25 percent
share is very different than the portion of the value that the
other 75 percent get from their taxed portion.
Finally, there is an even bigger difference with a substantially
different cost of capital for the state than what the producers
have. He ran his analysis using the same amount for cost of
capital for both just to show the difference federal take makes
to state value. Property tax is a fixed amount based not on
revenues but on the capital value of the physical infrastructure
that producers have built up and that takes up an ever larger
portion of the total pie that the state is not paying. So, the
state takes more and more of the net present value of the cash
flows at low price environments and at times that share is quite
substantial, sometimes a majority of the value the project
creates.
4:08:18 PM
SENATOR BISHOP asked because of the state's tax exempt status
from the feds if its' 25 percent participation was more
valuable.
MR. MAYER answered being tax exempt was the primary driver, but
not sharing the upstream costs was another big factor.
SENATOR BISHOP asked if another company had to be formed under
AGDC to get that advantage.
MR. MAYER said that was his understanding of the
administration's rationale.
4:09:23 PM
MR. MAYER summarized that the state gets a greater share
relatively speaking in lower price environments (because less is
going to the federal government) and more that 25 percent at
almost any price range.
4:10:28 PM
MR. TSAFOS turned to slide 14 and said the path laid out by the
HOA fosters the state and oil companies caring about two similar
things: the price of the commodity and making sure it gets
produced at the lowest possible cost.
He underscored that just because gas is indexed to oil doesn't
mean it's the same price. That indexation to oil merely defines
a relationship between two commodities, but the price can be
very different in different contracts. Evidence for this was on
slide 15 that graphed Taiwan's three long term suppliers:
Indonesia, Malaysia, and Qatar - all three with prices linked to
oil. Taiwan has two contracts with Indonesia, one signed in the
late 1980s and the other signed in the mid-1990s. The high slope
of the two contracts ran in tandem and indicated that a $10-20
increase in the price of oil generates a pretty significant
increase in the price of gas.
The Qatar contract was signed in 2005 at a time when the buyers
had the bargaining power. That relationship, even though it was
still linked to oil, was very different. So, even though the LNG
prices were linked to oil, the contracts were signed at
different times in different markets. So the price of LNG to
Taiwan, for Indonesia was about $20, for Qatar $7 or $8, and for
Malaysia $6 or $7. But in 2008 when oil was at $100 and they
were paying the Indonesians $19 and $20, Qatar got its deal
revised.
MR. TSAFOS said the lessons to learn are: first, don't obsess
over the link to oil and, second, that new contracts don't
impact existing deals. The reality is that most long-term deals
will probably be wrong and all contracts have provisions to
revisit things; the state's lawyers should have a strong review
clause in any contracts they write. The standard practice is to
have a price review every 4 or 5 years and once outside of that
cycle if things get out of hand. A contract with too much
flexibility won't be worth anything and a contract that is too
rigid is likely to be taken over by events, he advised.
4:17:04 PM
SENATOR MICCICHE asked what could trigger a review clause and
mentioned a scenario where LNG goes from $7.50 to $16 and
shipping goes up as well and asked if the trigger could be
caused by the price alone or the cost across the supply chain.
MR. TSAFOS responded that a price review is usually exercised
for two reasons: the first is volatility protection and the
second is the distribution of value between different
participants. He turned to slide 15 to explain volatility
protection: the idea being a shaky project can find commercial
ways to protect itself. The most typical is an S-curve. If you
don't have an S-curve you're like Indonesia: the price of oil
goes up and the price of gas goes up. The S-curve says I am
concerned that the price of oil may go down and I might not make
a good return on my investment, so I would like to slow down how
that relationship plays out as prices go down. I want some
insurance; and I want to make sure I earn $12 no matter what.
You can probably sign a contract like that as long as you are
willing to give up on the upside.
He said these contracts were not written to survive for the long
term and assume that at times the world will no longer
fundamentally represent what is in them and allow for making
fundamental price reviews. For instance, if you were to sign a
contract today and oil went up to $110 you couldn't raise your
hand and call for a price review, because that would be
unreasonable. However if it went up to $250, you could. A big
part of price review is triggered by these clauses.
MR. TSAFOS said a second cause for price review is triggered by
the distribution of value between different participants (slide
16). For instance, Equatorial Guinea when it was developing its
project thought its LNG was shipping from its port to the United
States, so it wanted a netback relative to the U.S. And just
like everyone else who got the U.S., wrong they did. So, when
the U.S. price tanked their sales prices tanked, too. That LNG
was then taken by someone else at the port, put on their ships,
and sold to Japan for $17. So, it leaves the port at $2 and ends
up at $17. When that happens the company can say the world has
changed because they thought it was going to the U.S. When the
company, BG, did that, the sovereign was very unhappy, because
they were taxing the LNG at 2 percent. And now the company, BG,
is making voluntary payments to the government of Equatorial
Guinea; the point being you can upset governments only so much.
He said this had also happened in Trinidad: they had a deal
where they thought they weren't sharing the upside so they
fought to change the terms. Yemen just recently concluded deals
to basically strike out S-curves, because they signed contracts
in 2006/7 that assumed a much lower oil price world.
More often it's the sovereigns who try to restructure, because
if you are an oil company, you actually buy the gas from Yemen
at $5 and sell it to Korea for $20: they care about the $20 but
only get taxed on the $5, and that's what creates tension. So it
does not matter to the oil company where along the chain that
value is distributed. The bottom line for what the state should
really care about when there is a gas deal in front of it is its
exposure to risk and if there are ways to protect the downside,
and usually that can be done by foregoing some of the upside.
The other thing critical to price is that timing matters. If the
buyers have the power, you won't get as good of a deal as when
the sellers have the power. And while this is pretty self-
evident, the reason he underscored was because you get tied to
that relationship. So, Qatar is still living in the bargaining
power of 2005 not the bargaining power of 2014.
4:25:12 PM
MR. TSAFOS said investors care about the price and the costs,
and the costs are what are essentially affected by what could go
wrong. In the current scenario the state is on the hook for 25
percent of the liquefaction and for a share of the 25 percent of
the midstream, potentially, depending on how the TransCanada
deal works through the GTP and the pipeline.
He showed some large complicated projects showing what kind of
cost escalation had happened to other projects (slide 16).
Sometimes they come on line on time and under budget, but they
usually don't. Some of the costs are global: the price of steel
going up and not much can be done about that: some are country
specific: in Australia a good living can be made working on
these projects, so when the competition for labor is so intense
because there is a once-in-a-generation commodity boom there,
the only way to secure labor is to pay up. The last category
that could cause costs to go up is very specific project issues:
an accident, a fire, strikes, the pipeline route, and other
things that can just go wrong. It's not a shock to have a 10 to
20 percent cost overrun, he said, and the slide showed a range
of projects with cost overruns ranging from 0 percent to 120
percent.
4:29:23 PM
SENATOR MICCICHE asked if a project delay can be beneficial in
terms of commodity price and value.
MR. TSAFOS answered that he could think of project delays where
the damage was less than expected but not what could be called
beneficial. Tying up capital does not make sense. During the
economic depression of 2008/9 demand cratered and at that time
there were projects going at 100 percent but they slowed down,
because there was no reason to pay people overtime to complete a
project to sell a commodity that no one was dying to get. Things
like that on the margin can make a difference, but, again, so
much capital is tied up in spending $40 billion you really want
the money to start coming in.
MR. MAYER answered that question this way: there is a big
difference between the delays they are talking about here in the
FEED process, and the ones that really count, which are those
that happen post-FID. Many projects have delays for one reason
or another in terms of the process, but at the point of FID the
deals have been done and that is when the real money is getting
spent. Delays after that point add up every year in terms of
tens of billions of dollars in NPV lost along with no revenue
coming in.
4:32:50 PM
SENATOR MICCICHE asked if he was saying that after the contracts
have been executed after FID that every moment not selling gas
is a delay and a hit to the bottom line, essentially.
MR. MAYER responded that maybe the contracts have been executed
and include a requirement to have gas to sell, in which case
that hurts; but if market conditions improve post-FID, there is
no benefit, because the state will not be signing new contracts
at a better oil price slope, and it would get the downside of
another year's delay and another year's interest on tens of
billions of dollars with no revenue coming in.
MR. TSAFOS said the revenue might even become negative, because
the state might be obligated to find something to sell if the
project is not on line. For example, Indonesia had a low S-curve
structure and, in fact, one of the operators was shipping gas
from Egypt that was previously fetching $17-18 for $3-4 because
they had to meet some commitments. Things like that could drive
the value of the delay; it generally tends to be bad in
different degrees of seriousness.
4:34:36 PM
SENATOR BISHOP observed that there were four projects in the
billion-dollar range came in on budget and with no cost
overruns, but then four other projects in the $37-60 billion
range had overruns of 15.6 percent to 45 percent. That
underscored that value equals getting the highest price possible
along with the lowest cost of construction possible, because
they want to get gas back to Alaskans at the cheapest molecule
price at the burner tip.
SENATOR FRENCH asked MR. Tsafos to talk about the risk to the
state of having only one project to sell at one time. How can
Alaska best protect itself against the fact that it is just
going - in one 12-month window - to the market to establish long
term contracts for all of the gas going through the pipeline for
a 20-year period.
4:36:26 PM
MR. TSAFOS said first - big picture - everyone will know what
kind of deal it is getting at the FID and if they are fairly
similar between the players, but if the market is timed wrongly,
the project won't get built. Less than 10 percent of the total
cost is spent before the FID in terms of the administration's
time table.
However, he said, there are other things to consider. One is
that selling the gas from a project of this type is a multi-year
affair (2-3 years). More important to appreciate is that Alaska
has one asset but it is targeting a marketing window that no one
else is targeting - no one is cutting LNG deals for 2022 or
longer. Because it is taking so long for this project to get
going, the window is different and the state might benefit from
the fact that it is tapping into a need for some companies that
are thinking strategically long-term that other players aren't
necessarily responding to. Before coming to Juneau he had
conversations with some of his Japanese colleagues who are
getting very excited about Alaska, because they are thinking it
is the next tranche after the Lower 48, after east Africa and
western Canada, and that could be quite beneficial.
Lastly, he said there is a possibility for Alaska to sign up the
gas in several blocks rather than one big one. There are three
trains and they usually come on line maybe six months between
one another and Alaska may still have some gas to play around
with. The bottom line is if the state is marketing gas and the
responses from the buyers are not good, don't worry; the project
just won't go forward and the sizeable money won't be spent.
That's typically what happens in LNG projects.
4:41:28 PM
SENATOR MICCICHE said his understanding was that you don't
necessarily have less risk because you have more projects. It's
not like Australia averages its risks and the huge cost overruns
were largely because of the amount of projects in a short time
and their associated labor cost overruns.
MR. TSAFOS answered he was right; but some of the risk also had
to do with the exchange rate between the Australian and the U.S.
dollar. Because of the commodity boom, international companies
earn U.S. dollars, but they buy Australian dollars to pay labor.
Alaska may not have the same types of cost overruns. The AKLNG
project is estimated to cost $45-65 billion and the $65 billion
is the overrun. That is how companies are presenting their
projects now: as a range.
SENATOR MICCICHE asked if the AKLNG project's royalty production
tax model was more advantageous than Australia's individual
contractual model.
MR. MAYER answered that there are a number of ways to set up
appropriate fiscal arrangements and Australia's is similar in
some ways to Alaska's. The Australian system is a profit based
tax as is Alaska's: for offshore projects there's no royalty;
for onshore projects there is a royalty but it is credited back
by the federal government. Contractual arrangements apply to LNG
projects in places like Qatar and Indonesia. But one thing
really stands about Alaska that is not present in a lot of other
projects, which is the sheer size of the midstream compared to
the upstream component. They talked about Gorgon being similar -
with a very big difficult costly upstream deep water development
being a big portion of the value, along with the pipeline and a
liquefaction project, whereas he couldn't think of any other LNG
projects in the $45-60 billion ranger where almost all of that
is in the midstream. In that sense, a tax regime that is focused
entirely on the upstream with value netted back to the upstream
is less likely to be of benefit to the state than something,
however it's structured, that focuses on getting value
throughout the chain.
SENATOR MCGUIRE said having alignment in the equity share is the
best way to go forward. She also appreciated Senator French's
question as to what happens if no one shows up and the fact that
the market takes care of those things. For her the last area of
risk for the state was in the midstream and not wanting to lock
into something like it did in AGIA (paying forward by $300
million) that seemed out of alignment with basic economics. She
wanted to be able to extricate in a place that isn't in
alignment with fair business and market principles. She said she
likes this bill, because it does make sense, and she likes
TransCanada as a partner, but they need to scrutinize the
midstream.
SENATOR GIESSEL said she had asked the administration to clarify
where those off ramps are and what they will cost.
CHAIR GIESSEL thanked the presenters and asked the committee
members to submit amendments by Tuesday at 9 a.m.
SENATOR FRENCH said they hadn't even heard the entire bill yet
and wanted another day.
CHAIR GIESSEL said she would take that under consideration. [SB
138 was held in committee.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| SJR 5 vs A.pdf |
SRES 2/14/2014 3:30:00 PM |
SJR 5 |
| SJR 5 Sponsor Statement.pdf |
SRES 2/14/2014 3:30:00 PM |
SJR 5 |
| SJR 5 Fiscal Note.pdf |
SRES 2/14/2014 3:30:00 PM |
SJR 5 |
| Gov Parnell letter on OCS Revenue Sharing.pdf |
SRES 2/14/2014 3:30:00 PM |
SJR 5 |
| Gulf of Mexico Act Sec 5.pdf |
SRES 2/14/2014 3:30:00 PM |
SJR 5 |
| Petroleum News March 2 2008.pdf |
SRES 2/14/2014 3:30:00 PM |
SJR 5 |
| SRES, enalytica 20140214 UPDATED.pdf |
SRES 2/14/2014 3:30:00 PM |
SB 138 |