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PLATTS ANALYTICS GLOBAL LNG
January 18, 2019
ANALYTICS REPORT nagasanalytics@spglobal.com
Ira B. Joseph, S&P Global Platts
THE LONG-TERM LNG CONTRACT PRICING PROBLEM: CASE SOLVED
Ira B. Joseph
Head of Gas and Power, S&P Global Platts
The LNG market is stuck for Asian buyers. While the Americas can comfortably rely on Henry Hub and Europe indexes to NBP or TTF, traditional oil-indexed pricing methods for LNG contracting in Asia are at odds with emerging trends in LNG pricing, leaving buyers and sellers separated well beyond the normal give and take in negotiating a deal. New deals continue to trickle out based on every type of indexation ranging from Brent crude to Platts’ JKM price for LNG in Asia, but the type of broad-based anchor index traditionally portrayed by the JCC (Japanese Crude Cocktail) over the last few decades remains the elusive glue for tying together the fragmented world of global LNG pricing. Is oil indexation of long-term LNG contracts dead? Not just yet, nor does it have to be. For now, the lack of a long and liquid forward curve in Asian gas pricing will keep oil indexation in the discussion, as the forward curve – accurate or not in terms of outturn pricing – is still the benchmark in terms of creditworthiness and financing. While liquidity in JKM, TTF, and Henry Hub continues to improve and is now a mainstay in pricing spot cargos, the role of oil still remains an important issue, even if the competitive landscape has changed between the two fuels. Bridging this pricing gulf on long-term LNG contracts between buyers and sellers remains the single biggest obstacle to the development of new liquefaction capacity.
Introduction
The LNG market is stuck for Asian buyers. While the Americas can comfortably rely on Henry Hub and
Europe indexes to NBP or TTF, traditional oil-indexed pricing methods for LNG contracting in Asia are at
odds with emerging trends in LNG pricing, leaving buyers and sellers separated well beyond the normal
give and take in negotiating a deal. New deals continue to trickle out based on every type of indexation
ranging from Brent crude to Platts’ JKM price for LNG in Asia, but the type of broad-based anchor index
traditionally portrayed by the JCC (Japanese Crude Cocktail) over the last few decades remains the elusive
glue for tying together the fragmented world of global LNG pricing.
Is oil indexation of long-term LNG contracts dead? Not just yet, nor does it have to be. For now, the lack of a
long and liquid forward curve in Asian gas pricing will keep oil indexation in the discussion, as the forward
curve – accurate or not in terms of outturn pricing – is still the benchmark in terms of creditworthiness and
financing. While liquidity in JKM, TTF, and Henry Hub continues to improve and is now a mainstay in pricing
spot cargos, the role of oil still remains an important issue, even if the competitive landscape has changed
between the two fuels. Bridging this pricing gulf on long-term LNG contracts between buyers and sellers
remains the single biggest obstacle to the development of new liquefaction capacity.
Liquefaction, Long-Term Contracts, and Pricing
With Platts Analytics forecasting the need for new liquefaction capacity by 2022, the ticking of the clock is loudening
if we assume a three-to-four year process from FID to commissioning for the building of new liquefaction capacity.
Sellers want and insist on needing long-term contracts to justify financial investments, while buyers appear largely
uninterested in signing deals due to any number of reasons that start with price and range all the way to volume
inflexibility. One of the most significant trends this decade has been the migration of long-term contracts from end
users to portfolios, which tipped the hand on the LNG pricing conundrum we face today, as it reflects how
assumptions of risk are evolving.
At the highest level, the question of why long-term LNG contracts need to exist in the future needs to be raised.
While the lists of proposed LNG projects continues to build on the back of staggering increases in stranded gas
reserves, the pipeline of new long-term LNG contracts remains small and infrequent. As a stop gap in recent years,
contracts have become shorter in length and smaller in volume, although this trend is far from irreversible under the
right terms if the sweet spot can be found between buyers and sellers. Outside of specific utilities, most buyers are
uninterested in such long-term arrangements in a world where supply seems elastic and abundant, while sellers
claim the need to have long-term contracts in order to primarily finance the development of liquefaction. From a
credit perspective, issuing debt without the view of, right or wrong, a forward curve, is much more expensive and
difficult to undertake. Hence, the need for a long-term contract. The battle lines on future LNG contracts have been
drawn and the logic goes as follows;
Buyer: “Exxon or Shell doesn’t need a 30-year gasoline contract in order to build a refinery. They take on the full
financial risk, so why do LNG producers need long-term LNG contracts in order to build liquefaction plants?”
Seller: “If a 5-year forward curve existed for Asian gas like it does for crude, we would consider it, but as it stands, no
such mechanism exists and neither Henry Hub nor TTF reflect our regional gas balances.”
In the past, contracts were secured as part of a broader integrated project that addressed security of supply issues
for the buyer and security of demand issues for the seller. With so many countries now buying, so many countries
now selling, and so many traders and portfolio holders in between, the idea of a long-term contract could be viewed
as a bit of an anachronism if looked at through the lenses of crude oil markets. So does a major oil company need to
sign a 20-year gasoline contract to build a refinery; does an NGL company need to sign a 20-year deal to build a gas
processing unit? The answer to these questions in the past was that these other commodities offered long-term
forward curves as a means of offering some price security (or at least price direction), whereas gas did not. Of
course, this difference is less of an issue these days given the rise of Henry Hub, TTF, and JKM as established
markers. That said, the use of Henry Hub or TTF in Asia has always come with major caveats. JKM is well on its
way in terms of surging liquidity, but it is not yet there, which gives it a bit of a chicken and egg problem when it
comes to using it for long-term LNG contracts. In a positive move, we are starting to see this barrier come down for
JKM in terms of deals by some portfolio players.
The Oil/Gas Price Inversion Blows up Rationale for Traditional LNG Pricing
Another key change for LNG contracts is that the pricing relationship between oil and gas has shifted from
downstream to upstream and in many cases, it has become completely inverted. In the past, gas offered substitution
potential for oil in the home heating market or power sector, so pricing one off the other kept gas competitive and
justified the build out of significant midstream infrastructure such as liquefaction, shipping, pipelines, and
regasification. In addition, a highly liquid spot market for oil pricing allowed for better hedging, even if oil indices such
as the Japanese Crude Cocktail (JCC) in Asia were difficult to pin down due to their ever changing import makeup
each month. In Europe, either gas oil or fuel oil pricing in the north or crude oil pricing in the south were traditionally
used for LNG pricing due to their use in traditional pricing of pipeline gas. As spot gas pricing has taken over the
Continent in the past 21 years, the need to tie LNG prices to oil has essentially evaporated in favour of spot prices.
In the future, the downstream overlap between oil and gas will be extremely limited and therefore the fuel
substitution-based rationale for using one to price the other makes about as much sense as pricing a Twix Bar off of
Coca-Cola because they both happen to contain sugar. Within the downstream sphere, the price of gas has largely
migrated from a seasonal, R/C-related sine wave flowing around a central tendency oil price to a coal-to-gas
switching price centered on gas consumption in the power sector. Oil's use in the residential/commercial sector is
now largely based on legacy infrastructure issues in places like the US northeast or NW Europe, as gas prices have
dropped well below gas oil in both areas on a sustained basis due to the introduction of liquid spot gas markets.
Substitution is rare and is now tied more to investment than short-term market forces. While gas and LNG are
making some inroads into the transport sector via fleet trucks and bunkering fuel, the competitive remains fairly
limited and largely policy driven such as the 2020 IMO change on sulphur specifications.
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Evolution of LNG Contracts Shows Smaller Sizes; Volume of Long-Term Deals Relatively Steady
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The signing of 20-year LNG contracts continues to occur, but the volume behind each one of these deals is
considerably smaller than in the past.
What is also of note is that they are not
being signed by some of the larger
traditional players on the sell side. On the
buy side, new 20-year deals out of the
US are being used as benchmarks in
their own right to negotiate alternative
deals elsewhere in the world. Buyers are
using US deals in a "match this" type of
negotiation, while the sellers are
currently balking at the notion that start-
up ventures in North America offer a credible marketing threat to their pricing goals.
Forcing the hands of the LNG sellers is not necessarily the rapidly rising volumes of stranded gas in the ground, but
more likely, the potential impact on impeding growth in oil and NGL production. Without the option (or really the
desire) to flare gas on a sustained basis,
the necessity to find outlets for gas is
becoming a significant issue in certain
places like the Permian, Eagle Ford,
Bakken, and Marcellus Basins in the U.S or
the Montney Basin in western Canada. The
pricing relationship between oil and gas
has gone from being a complementary
relationship at the burner tip to a
supplementary relationship at the wellhead,
as the spread widened after 2005 between
oil and gas prices (chart).
Platts Analytics’ long-term forecast shows this wider split remaining. Even more significant than the WTI/HH or
Brent/NBP relationship is the intense downward pressure on gas prices relative to oil at basis points such as Waha
in West Texas. The possibility of gas prices at the wellhead being driven down to figures that are less than a U.S.
dollar and potentially negative on a temporary basis is a real scenario, as both investments in midstream and
domestic gas demand growth struggle to keep up with supply elasticity being turbo charged by oil and NGL values.
In a higher oil price case, the problem becomes more acute. In this case, the Twix Bar to Coca-Cola metaphor is still
apt, but the oil and gas price relationship has become severely inverted, albeit no less reliable in terms applicability,
which has significant implications if you are going to continue pricing one off of the other.
What further complicates this upcoming period in LNG contract history is that not only are new projects competing
with each other to sign deals, but new projects are also competing with established projects in search of deals to re-
sign volumes that are about to expire. Older contracts are largely oil-indexed, while new contracts are blending in
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Gas prices have deteriorated vs. oil by the most in North America, which makes LNG projects more enticing…and necessary
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Source: Platts Analytics
spot gas indexation such as TTF or JKM, although oil indexation is still being widely offered and applied on new
deals. The first wave of new US projects are tied to Henry Hub, although the tie is relative to tolling costs for
liquefaction and not delivered prices. More of these deals are being signed, but primarily to be used as leverage.
Case in point, of the roughly 200 bcm/yr.
of long-term LNG contracts that will be
expiring between 2020 and 2026, a full
30% will be tied to Qatari deals. So while
the market focuses on a US contract
here or PNG contract there, in reality, all
new LNG contracts are tied directly or
indirectly to Qatar negotiations and how
these volumes will be re-signed. Just
about any contract now being signed is
swiftly flown to Doha as the starting point
for renegotiations on these expiring volumes in question. A cottage industry of sorts has emerged among Asian and
European buyers – the Venture Global LNG deals are a prime example – signing HOA, MOUs and even some SPAs
with US buyers just to provide leverage on larger volumes up for grabs from the Mideast or Asia.
A New Type of LNG Contract Price
As a starting point, Platts Analytics proposes a form of contract that borrows from the past, but also recognizes the
changing nature of how gas is produced and how gas is consumed. At the highest level, LNG needs to move on
from a world where it competed with oil to a world where it will need to compete with coal and align with renewables
as a fuel to support intermittency in power production. These factors suggest a lower breakeven price for delivered
LNG into the market, particularly in countries like India and portions of China, where the bearable price for LNG and
buyers at the burner tip is significantly lower than higher GDP economies such as Japan, South Korea, or the EU.
Otherwise, LNG imports will need to be subsidized indefinitely, which will increasingly makes battery storage a more
viable alternative to LNG and gas in the critical and potentially lucrative intermittency space tied to renewables.
This lower LNG price will not be achieved by cutting infrastructure costs along the value chain. Without some major
technological breakthrough, the assumption that liquefaction, transport, or regasification costs can be lowered by
any significant degree is a false one, no matter how much standardization emerges for each component. The fact
will remain that moving LNG from point A to point B or C remains a highly costly proposition from both a capital and
operating perspective, especially when compared to oil, NGLs, coal, or even the deployment renewables and battery
storage.
Of course the trick for LNG developers is protecting netbacks and margins in an environment where the outlook for
absolute gas prices will be dropping. Addressing these lower price targets must start with offering a peak price for
the gas, which will protect the buyer from the effect on spot prices of a supply disruption on inclement weather,
causing temporary tightness in the global LNG balances. For the seller, not only is a minimum price needed to cover
the capital and operating costs for building an LNG train, but also a recognition that the upstream economics of
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Long-term global LNG contracts start expiring en masse post-2020; what will replace them in the spot market era?
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LNG contracts by buyer Changes in LNG contract obligations pre/post 2020
producing gas as a precursor to creating LNG are largely dictated by oil economics. With East Africa and NE
Australia being the noted dry and CBM gas exceptions, the economics of associated and wet gas production are
broadly assumed to be the driving factors in the performance and sustainability of a well, not to mention drilling it in
the first place. The US, Qatar, Russia, and large portions of Australia will provide the bulk of the marginal gas supply
that will feed LNG production and all of these sources are largely wet gas producers.
The Gas Price/Oil Revenue Connection
Said another way, LNG developments will
need feedgas that is not only
inexpensive, it also essentially needs to
be free of revenue considerations for the
producer. In fact, as gas revenue
assumptions deteriorate at the wellhead,
cost assumptions rise, as the gas needs
to go somewhere whether the seller will
be getting paid or, in a more extreme
case, will be paying others to take it
away. The outlook for gas prices at the
wellhead need to be set at either zero or as a cost associated with the profitable production of crude oil or natural
gas liquids. Therefore, the approach we are taking here shifts the focus away from just the delivered gas price itself
and more onto either supporting or capping the revenue coming from a producing well. To support the seller, the
goal here is to establish a formula that allows for an oil and gas producer to be revenue neutral outside a certain
band of delivered gas or oil prices. Also known as kink points, these pricing points establish parameters for the
delivered price based on a historical analysis of what is an appropriate band.
Based on our analysis, we believe that the oil price band can be set at $64 per bbl on the high side and $29 per bbl
on the low side ($5-$11 per MMBtu equivalent). What we have found over the last two decades of tracking prices is
that this range appears to be amenable to both buyers and sellers on a sustainable basis. Oil prices above this level
tend to lead to either fuel switching or demand destruction for buyers and prices below this levels trigger the need for
production shut-ins, regardless of where gas fundamentals reside. Herein lies the problem for gas; half of the
balance is operating outside its control.
Here, the assumption is that Asian buyers will stick with oil prices as their primary form of indexation and sellers
embrace this choice as a means of protecting revenue. In the past, long-term contract LNG prices with kink points
were described at S Curves. At pre-determined points in the S Curve, the price of the LNG would change at a
decelerated rate relative to the change in the price of oil on which it was based. LNG prices would still go up on the
high side past the kink point and still go down on the low side below the kink point, but the financial burden for the
LNG would be reduced in either direction.
Reverse the Price
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Outside of $29-$64 per barrel, reverse the direction of oil-indexed contract LNG price for seller to stay revenue neutral
Brent Crude Oil Price in $ per barrel
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What we are proposing is a more radical version of S Curve changes at these kink points. The change in LNG prices
would not just ease the financial burden; it would reverse it completely in our base case. The goal here is to look at
pricing as a reflection of changes in revenue to the producer as a means of sharing the burden of prices falling
outside what we would deem the normal range of business. The goal here is to use price changes in gas relative to
oil to keep sellers revenue neutral above and below a certain price – in this case $29-$64 per MMBtu – by lowering
contract LNG prices when crude oil prices climb above a certain levels and raising LNG prices when crude oil prices
drop below a certain level.
By doing so, these countervailing changes in contract LNG prices mirror the financial decisions currently facing oil
and gas producers, while also protecting buyers from outside vulnerability to oil markets or potential disruptions in
LNG flows. This decision is based on the assumption that the higher oil prices climb, the less significant gas prices
become to the revenue stream, given that more gas is being produced without an underlying signal from the demand
side. Conversely, when crude oil prices collapse, it will be more important to garner revenue from the gas stream
due to the deteriorating economics of producing the crude oil or NGLs.
The JKM Option
While we are fully aware that JKM spot prices for LNG move somewhat independently of crude oil prices, the
influence of one on the other is still reflected in the nominating patterns of contract holders that reflect relative value
of contract LNG versus spot. As we mentioned above, the wholesale expiration of many oil-indexed contracts in the
next decade will offer a choice between re-signing on an oil-indexed basis or shifting to JKM, TTF, or Henry Hub
indexation. If buyers were willing to stick with
oil indexation, we would propose that the kink
points for an LNG price reversal would take
place at $29 and $64 a bbl Brent, which is the
equivalent of $5 and $11 per MMBtu. Above
or below these points, LNG prices would
reverse course at the same rate of change as
the oil price in order to keep the revenue
effect neutral on an incremental basis. If
contracts were to be based on JKM alone,
the kink points would still hold at $5 and $11,
but at these levels, LNG prices would remain flat for buyers as long as oil prices remain in the $29-$64 a bbl range.
In this case, the revenue outcome would not be neutral, but would still protect both parties from major LNG
imbalances.
If the LNG contract was JKM-indexed and crude oil dropped outside of this range, the same type of revenue
changes would begin to kick in. In this case, for every $1 per bbl of movement outside the $29-$64 a bbl range, the
LNG price would invert (see chart) by roughly $0.16c per MMBtu (the gas price equivalent of $1 per bbl). In a high
JKM spot price world above $11, the contract LNG price would drop by $0.16 per MMBtu if crude is over $64 and the
price would rise by $0.16c per MMBtu if crude dropped below $29. From a crude oil producer’s perspective, the
change is this incremental portion of the contract price would be revenue neutral, although the absolute JKM
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Outside of $5-11 JKM and $29-$64 oil, reverse the direction of JKM-indexed contract by $0.16/MMBtu for every $1/BBL oil move
Platts JKM Spot Price in $ per MMBtu
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contract price would not, as underlying JKM-indexed contract prices would remain flat – corrected only to oil – as
long as spot JKM was outside the $5-$11 per MMBtu price band.
While it would be appropriate to debate where the kink points should actually be – and how they should change over
time – for either the crude oil- or spot gas-indexed option, the underlying structure remains the same: creating
upstream and downstream protection for oil and gas prices in a world where oil and gas largely have an inverted
relationship and do not compete. Exposure to oil price volatility is still a very real issue, but is manageable by using
this type of thinking if long-term LNG contracts need to remain a mainstay of the global LNG market.