Editor’s Note: The following segment is one in a series by NGI’s LNG Insight focused on exploring how the global liquefied natural gas (LNG) market works. The conversations in this series will also analyze news and the issues that matter most to the industry in North America and beyond.
Brad Hitch is head of LNG for Pareto Commodities. He has worked in the energy sector for more than 20 years, holding various trading and origination positions at Barclays Capital, Enron Corp. and Merrill Lynch and as a consultant. Before joining Pareto, he was based in London as vice president of portfolio management for Cheniere Energy Inc. He holds a bachelor’s degree in accounting from the University of Kentucky and a master of business administration from the Wharton School of the University of Pennsylvania.
NGI: How has the LNG sector changed in recent years, and how different is it since you started working in the industry?
Hitch: It is a very different one from the market that I first encountered at the turn of the century. At that point, the market had been growing for a little over two decades in a very specific way. Liquefaction projects were built to monetize stranded gas by marketing LNG to power and gas utilities that otherwise had little or no access to natural gas. The finance for these projects was underpinned by long-term, take-or-pay sales contracts, which would typically last for 20 years or longer. Without traded natural gas markets, the buyers would agree to pay a contract price indexed to oil, which is logical as refined products would have been the alternative fuel.
NGI: Were those contracts more restrictive?
Hitch: Yes, they also greatly limited the ability to divert cargoes away from the intended market — effectively negating the possibility for re-trading cargoes and turning a potentially flexible form of transportation into a pipeline on water.
NGI: How has the market evolved since?
Hitch: One of the biggest changes that kicked in at the turn of the century was an LNG market that had been built mainly to serve Asian and some southern European demand began to integrate with wholesale markets in the United States and Europe. At first, that integration meant little more than optimizing marginal cargoes in a new and tiny spot market. But over the years, it has grown to become an important factor, even pervading the project development process itself.
When the LNG market began to be relevant for commoditized gas markets in Europe and the United States, it attracted the attention of traders in those markets. Initially, this meant former merchants like Enron Corp. and El Paso Corp. setting up LNG trading desks. When those companies exited the scene, the trading arms of investment banks became active. The banks themselves largely exited in the wake of the financial crisis, but not before large commodity traders like Vitol and Trafigura Group Pte. Ltd. had gained a foothold.
The traders have become an important part of the market over the years as their share of volumes has grown and served as a catalyst for moving the market away from the old “pipeline on water” model to a much more dynamic market. This cannot be overstated.
NGI: Is it fair to say that most LNG is still bought and sold under long-term agreements even though spot trading continues to increase?
Hitch: It is fair to say, but spot trades and long-term contracts are not mutually exclusive. Most of the cargoes produced by U.S. export terminals are being delivered under long-term contracts. The fact that there are long-term contracts underpinning the financing of these projects does not prevent those volumes from reaching the spot market. The more traditional long-term contracts had diversion restrictions which inhibit spot trade.
The advent of U.S. LNG producers has led to more spot trading and helped accelerate a trend that was already gaining momentum.
NGI: Can you explain how LNG supply agreements are generally structured in the United States? How is the fuel bought and sold?
Hitch: There are two basic types of contracts. The first is the tolling structure where you have an owner/operator that effectively provides a service in exchange for a fee. Gas is purchased by customers and delivered to the facility where it is liquefied and returned as LNG. That describes a basic tolling model, but of course in LNG you need to factor in multiple buyers sharing things like storage and berthing facilities, for example.
The other type is the sales purchase agreement, or SPA. Under this model, there’s a very clear title transfer at the loading facility. The LNG buyer is not concerned with purchasing feed gas and liquefaction, he’s purely responsible for arranging transportation and taking delivery of the LNG. He doesn’t take ownership of the LNG until it is loaded. This is the model that Cheniere uses. It’s also being adopted by some of the new developers.
NGI: Are other large producers, such as Australia, Russia and Qatar, now modifying their commercial arrangements in response to how U.S. producers have structured their supply agreements?
Hitch: I don’t know that they’ve necessarily had to yet. For example, the Australian projects that have gotten off the ground — and there has been a very big expansion of liquefaction in Australia — a lot of those contracts were written prior to U.S. growth at a time when they would not have had to react.
The Qataris have announced that they will bring a large expansion online this decade. That will be happening in the aftermath of surging U.S. LNG production and a market that has seen soft pricing in the wake of those volumes. So, we’ll wait and see how they respond.
NGI: Do you expect more long-term supply contracts to be renegotiated if global LNG prices remain low?
Hitch: It’s difficult to see that happening because there’s so much tied up in these contracts. There is a lot at stake for project developers and financing banks, which I think would resist very strongly. When I read an article that says a buyer is going to renegotiate their existing contracts with one of the LNG producers, I am generally not optimistic. Even if the producer entertains discussions, I can’t imagine they would go very far.
That doesn’t mean that producers will not work to make the buyers more comfortable in a down market with operating or other concessions. A buyer could presumably ask for a contract extension in exchange for a lower price, but the producers would be opening Pandora’s box by allowing buyers to renegotiate existing contracts.
NGI: The LNG market is still evolving and not necessarily as liquid as the global crude market or U.S. physical gas market. Given that, is there any dominant price or effective index for LNG right now?
Hitch: People would debate that question. I’d say there isn’t. You could make the argument that the Japan Korea Marker (JKM) is the dominant benchmark because it’s the most visible LNG price index. You could argue that the Dutch Title Transfer Facility is the dominant factor in LNG price formation right now, but it is a natural gas price rather than an LNG price.
If you dial the clock back to when the market was tighter, you would have said that JKM is the dominant market for price formation. In my view, a dominant index for a given commodity is going to be most important for price formation in any kind of market — whether tight, loose, or balanced — and LNG does not have that. Of course, this aspect of the market continues to evolve, and people are working on it.
NGI: How is U.S. LNG bought and sold?
Hitch: This goes back to how the SPA and tolling models work. In both of those cases, long-term contracts were signed between the facilities and the offtakers. Those long-term contracts will prevail, even in a low-price environment. If you signed an agreement with Cheniere to take a cargo from Sabine Pass for 20 years, and your formula price was a percentage of Henry Hub plus some constant, then you are going to pay what you agreed to in the long-term contract.
The next natural question is ”where does the spot market fit into that?’ Of course, the long-term buyer may have sold the right to lift the cargo to somebody else, and in fact, it might have been sold two or three times before it ever gets lifted. The value of that LNG is going to be higher or lower in the spot market depending on the demand for spot LNG at that time. For this reason, the market needs a good spot index and development of more financial tools. If you’re buying LNG under a long-term contract, you need a good mechanism for managing spot risk.
NGI: Are spot trades mostly linked to natural gas prices?
Hitch: Not necessarily. They can be, and given how much LNG has been going to Europe, it is probably happening more now than it has in the past.
NGI: Are long-term contracts mostly linked to oil then?
Hitch: I would say most of them are. Outside of the United States they were linked to oil almost exclusively. From what I understand, though, some of the newer projects outside the United States have started to incorporate European gas price indexes into some of their deals.
One other thing that trips people up when they’re new to LNG is the time scale we’re talking about between when a long-term contract is negotiated and when the project actually enters service and begins to produce LNG. There will be at least four or five years between the start of that contract negotiation and first production.
NGI: We hear about Europe serving as a balancing arm or market of last resort for LNG. Why is the continent described this way?
Hitch: Europe is a big market; it has a lot of demand. It’s also a mature wholesale market. And as a result of that maturity, it has a lot of flexibility within its system. For example, there’s gas storage in Europe. If there’s too much LNG in the market, you can put it into Europe, and it might find its way into storage. There is also fuel-switching capability in the power market there. As prices go down, more gas gets burned, which helps with the balance. There’s also a lot of regasification capacity there, which had been building up in the years before U.S. production was contracted.
NGI: Does that mean the market in Asia is not mature, or is lacking certain natural gas infrastructure?
Hitch: Asia certainly has a mature LNG market. The difference stems from the fact that Northwest Europe also has its own production whereas gas demand in Asia was often served by LNG imports. With production comes more infrastructure and more places to store gas. There’s also more incentive to pay for storage.
NGI: We’re hearing more about the possibility of LNG supply shut-ins because of low prices, particularly in the United States. Why would U.S. terminals be among the first to shut in supplies?
Hitch: The flexibility of the contracts is one reason. The existence of a large wholesale gas market is another. The fact that you’re pulling feed gas from the wholesale market in the U.S. means that the opportunity cost of liquefying it has a transparent value associated with it.
If you’re producing LNG from a project overseas that was purposely built to take gas from an oil discovery, your marginal costs of producing that gas are going to be very low — if not negative. The opportunity cost of gas from the U.S. wholesale market effects a higher relative marginal cost. Participants in the U.S. market should be thinking about the short-term economics for U.S. LNG projects as well.
NGI: If enough gas is shut-in and forced back into the U.S. wholesale market, what sort of impact would that have?
Hitch: You would expect it to lower U.S. prices. It would also have an impact on shipping. If more LNG carriers suddenly become available due to planned shut-ins, you would expect lower shipping rates. Lower feed gas and shipping in turn could potentially reopen a shut arbitrage window. When people talk about shut-ins it’s funny to hear them state confidently that they will or will not happen. The industry doesn’t really have much experience to draw upon. U.S. production is relatively new and is only ramping up now. That increase is taking place in an oversupplied market. Oversupplied LNG markets have been a rarity in the past. So there is a lot of uncharted territory here in my humble opinion.
NGI: How long would a potential shut-in last?
Hitch: It’s hard to say. People throw the term “shut-in” around loosely. If you’re producing cargoes each month from a few different trains and two of your customers call you and exercise their option not to lift cargoes, does that qualify as a shut-in? I suspect what will happen over the summer is that less LNG will be sold from the United States, but it won’t rise to the level where whole trains are shut down for long periods. Whether market analysts choose to use the word “shut-in” after the fact will be arbitrary.
NGI: Given the current oversupply and low prices, are some second wave facilities in the U.S. unlikely to be built?
Hitch: The spot price for LNG today is below what a project developer would need to construct an LNG project. But LNG projects are not built against spot market indexation, not yet anyway.
The first point to make is that with or without high spot prices you would have expected some rationalization given the total number of projects that have been proposed. Furthermore, you would expect that demand growth will absorb this oversupply in time.
Regarding the impact of current prices, one could argue that buyers should have been factoring the risk of price fluctuation into their purchase plans when prices were high. If you follow that line of thinking, then you can make the argument that rational buyers shouldn’t abandon long-term contracts now that prices are low.
We all know, of course, that economic behavior isn’t strictly rational, and you would expect prospective buyers to wait a bit longer before signing new long-term deals. That in turn makes it disproportionately more difficult for greenfield project developers, which the second wave typically are, compared to developers of expansion projects.
NGI: Where does the U.S. currently stand in the global LNG market given some of the dominance of other producers such as Australia, Russia and Qatar? Can you discuss U.S. ascendancy in this space?
Hitch: There are some people who make a living talking about this, and I’ve never been one of them. I do think that based on resource alone, and long-term value proposition, the United States should be a leading, if not the leading, exporter. There is such an abundance of natural gas and such a relatively good environment for project development that the United States should continue to produce more LNG over time.
The Qataris have an amazing resource base as well, they’ll continue to develop that and grow it, as will the Russians. For any one country to become more dominant than another would mean production growth slows somewhere, and I don’t envision that. I think we will see a period of continued U.S. expansion but also continuing competition.
NGI: As interest grows in LNG exports, what are some of the key market factors that people should be paying attention to?
Hitch: For those in the United States new to LNG, I would first direct them to look at and understand European storage levels and the current volume of gas coming from the tailgate of Northwest European import terminals. Obviously, you want to be looking at European and Asian gas prices, but I would monitor the evolution of gas storage in Europe as we move from withdrawal into injection season. Also, the actual gas flow out of the European terminals is a good indicator of whether there is excess supply in the market.
I also think that you need to be keeping an eye on whether LNG cargoes are backing up at any location. Are you seeing LNG cargoes congregate in one space for any other reason than they are simply waiting to get into their loading slot, or are a lot of cargoes floating because they can’t find a buyer — even with low prices?
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