platts analytics global lng€¦ · platts analytics global lng january 18, 2019 analytics report...

PLATTS ANALYTICS GLOBAL LNG

January 18, 2019

ANALYTICS REPORT [email protected]

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.

Footer : Never change the footer text on individual slides. Change, turn on or off footer by using Data color order: Complimentary colors:

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


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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Europe Americas Mideast PortfolioRest of Asia China Japan

Long-term global LNG contracts start expiring en masse post-2020; what will replace them in the spot market era?

Bcm

-100 -50 0 50 100

2020-2030

2017-2020

Americas Mideast Europe Portfolio

Rest of Asia Japan China

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


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


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 tied to JKM

Index only if oil price in

$29-$64 per bbl range

Downward adjustment to

JKM Index if oil above

$64 and JKM above $11

Upward adjustment to

JKM Index if oil below

$29 and JKM below $5

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.

platts analytics global lng€¦ · platts analytics global lng january 18, 2019 analytics report...

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