We all know that energy markets are fully loaded with the unrelenting volatility of price movements, the apparent boom and bust cycles, and the scaremongering of the dreaded prognosticators. All those with the words “trader” in their automated email sign-offs are supposed to love the “v” word, take it away and they end-up in a state of despair, but fully exposing themselves to the market’s precarious unpredictability has become a thing of the past. A few decades ago we found the only way to switch-off was to drink beers at night and wait for its anesthetic properties to kick-in. But now we won’t switch the bedroom light off until we feel we’re “fully hedged”, or at least holding manageable risk. Nonetheless, there are still two parts of the LPG sector that we seem more at ease with when it comes to risk, and the duration of time we are prepared to hold that risk for. One relates to the period of time we are prepared to commit to take a ship on time-charter at a fixed rate, and the other is the term contract, purchase or sale, but nearly always with a fixed portion attached to a quasi-market price mechanism.
I have always felt traders need both, and although of course the risk can be offset by taking positions on both sides of the supply/demand division, the fixed price risk is there, whether it is the premium or discount to the Saudi Aramco CP, the delivered number above CP into China, the hard-and-fast terminal fee for U.S. exports, or the delta attached to an FEI contract. The question then becomes, how long can you commit for? In other words, how long until the market turns on its head and somebody is left holding the baby. The rule of thumb used to be a year, as long as it had the word “evergreen” written somewhere in the duration clause. Yes, there were contracts in Saudi Arabia or in the North Sea that felt as if they were longer commitments, but the key was to be able to re-negotiate, or exit, on an annual basis. Then came the U.S. export contracts, and matching the term aspirations of both the seller and the buyer. As we move closer to the second half of 2020, in one of the most dramatic of years, the scrutiny on U.S. exports is not only focused in the present, but also on the years to come.
I fully admit my late 2019 antics in SIMON SAYS, was banging-on a lot about export capacity in the U.S., especially along the Gulf coast. The two related buzz words of last year were “take-away” and “capacity”, whether it was ME2 up in the Marcellus/Utica shale region, or a lack of pipelines linking to the Houston area from the Permian patch in Texas, fractionation constraints causing the build-up of Y-grade NGLs, or simply not enough slots at the four main export terminals. I remember the slides at RBN’s XPortCon this time last year, showing an imbalance between new production destined for the export market and the dock capacity to handle it.
Enterprise were slightly ahead of the game, having announced in September 2018 a 30% increase in the capacity of their Houston Ship Channel facility by 175 M Bbls/d, to a total of 720 M Bbls/d, for start-up in the second quarter of 2019. The capital investment was nominal, aiming more at loading efficiency, rather than any major structural investment. It didn’t really ease the pressure on capacity, but it did send a signal to the market that Enterprise could expand capacity with only a “nominal” investment. It also threw an initial shockwave into the Boardrooms of companies looking to build their own export terminals from scratch. Yes, there was a need for extra capacity, but was there room for more terminals?
We need a bit of history here. The Enterprise and Targa terminals have pretty much been around in LPG parlances forever, originally built for imports, but now firmly ensconced as huge volume export facilities. But at the beginning of the U.S. shale revolution, capacity was still the key word, especially the lack of it! The main problem was chilling the warm ambient propane down to the fully refrigerated temperature required to load the product onto the world’s VLGC fleet. In 2013 there were contractual arrangements for about 120 cargoes over the year, with over 100 liftings from Enterprise and the balance from Targa. By 2015, Sunoco’s Nederland facility was on stream, and nearly 250 VLGCs in total, or their equivalent, were being loaded for export from the three terminals.
The rush for contracts by the international trading community had begun, whether it was the Japanese and Koreans believing this was a cheaper source than Middle Eastern CP product, or the Chinese just believing it was going to be cheap. The traders and majors were also keen to get contracts. The frenzy meant a lot of players were willing to commit to high fixed terminal fees for periods far greater that the one-year rule of thumb. Vitol had been tempted into a ten year contract with Enterprise, as an alternative to building their own facility in Beaumont Texas, together with one-third partner Itochu. Others happily settled for 5 year deals, as the export terminals quickly recognized that the returns associated with low double digit terminal fees were clearly going to bolster their financials.
But there were two issues that would bring a serious shock to the party. Firstly, was the fact that the market was significantly changing. By 2017 export capacity had been further expanded with P66 opening in Freeport, and Enterprise creating yet more efficiency improvements. By now Enterprise were supplying 50% of nearly 500 VLGC equivalent cargoes per annum. The expansion in volumes was having two effects. It was giving U.S. producers a growing alternative market outlet, reducing the discounted label that had previously been attached to it, and was bringing Mont Belvieu values relatively higher. At the same time more LPG was hitting the Asian market, and as fast as new demand such as PDH was coming on-stream, it couldn’t keep pace with the supply. An Asian market influenced by the apparent premium pricing associated with Saudi Aramco’s CP, was now inching down in value, as sellers looked more to the petrochemical sector, not known for paying above market. The ARB was being severely tested, and although the freight element took a downward slide, the terminal fees came under severe pressure, culminating in a rush of cancellations, especially in the summer months.
And then there was the very large amount of U.S. cargoes indirectly heading to Chinese buyers through intermediaries, such as Mabanaft or E1, the so-called “sleeves”. When the terminal fees collapsed, and losses mounted, Oriental Energy and others tried to re-negotiate from their long term commitments. The losses involved were huge, and there were many companies who moved from bumper profits in the early shale days to bumper losses. The U.S. exporters, especially Enterprise, had played the right cards. They had maximised the length of contracts and had contracted mainly with financially strong companies.
But, this was a lesson for all. Those who still had contracts to perform saw out the balance periods, through mainly to this year and last. The slots were still pretty much full, topped up with smaller contracts for shorter durations. The capacity was limited. But after two to three years of mid-single digit terminal fees, and parties reluctant to go beyond the one year deal, the lack of capacity meant any production shock in the Middle East would be met by greater interest in re-sale cargoes out of the U.S. Gulf. With the increased tensions resulting from the attack on Saudi LPG facilities in the third quarter of last year, together with the reduction in Middle East LPG exports, U.S. cargoes became hip again. With a pretty finite number of cargoes for re-sale, terminal fees started to rocket up, not only into double digits, but even surpassing the heady days of the initial surge in buying interest some 5/6 years previously.
Again came the call for an expansion in capacity. Again came the rumours of possible new entrants to the export market. Again came the news release from Enterprise. In addition to the 175 M Bbls/d expansion due for completion at anytime in the third quarter 2019, the company announced a further 260 M Bbl/d expansion for start-up in the fourth quarter of 2020. Again it was via the “efficient use of capital”, utilizing the latest technology to modify and expand existing facilities. Targa followed suit with the expansion of their butane loading capability, P66 were already able to put a couple of extra cargoes into the market per month, with talk of further expansion, and Energy Transfer were looking to un-lock the constraints of having nearly 4 day loading slots, following the end of the original Shell contract in the first half of 2020, to free up potentially 20% more capacity.
No new terminals were announced.
I haven’t added-up the committed investment dollars, but I don’t think anything that was announced, by any of the terminal operators, would be sitting high-up on their CAPEX list. It was all about “efficiency”. So with all the expansion I have only seen about 10% more VLGCs coming out of the Houston Ship Channel since 2017. The growth in propane exports in the U.S., that we certainly saw in the second half of 2019, were driven by the expansion of Marcus Hook, post the completion of ME2.
So, there’s good news for the U.S. export terminal operators, with no new players joining the list! The bad news is that the fall in oil prices exacerbated by the coronavirus pandemic, means that export volumes can only be kept-up by a greater buying activity in Mont Belvieu by the export terminals. That can only push prices higher domestically, potentially killing the ARB, and killing the confidence of international buyers to enter term commitments beyond one year or even less. WTI has amazingly come back to nearly $40/ Bbl at last night’s close. Now last year, in RBN’s XPortCon, a $50/ Bbl price for WTI was still only likely to result in 70% of the new expanded capacity being utilized in 2020. At $40/ Bbl we may well see exports drop to below 1 million Bbl/d, which is where Enterprise wanted to have their capacity by the end of the year.
Now with a few contractual musical chairs having recently taken place, especially Shell significantly cutting back in Nederland, and BP reducing cargoes from Enterprise, there is still a commitment to find over 1.25 million Bbls/d for export, pretty much where we were last year, give or take. Now, if production cutbacks result in lower export potential in the U.S., and assuming all new barrels are due to hit the international market, then this is why exporters will have to enter the domestic market to make up the difference. Expect propane stocks to initially fall, prices to relatively increase, cancellations to become the monthly norm, and yet more uncertainty. So if a terminal operator asks for a two or three year contract, are you going to commit? But then I did hear mentioned this week a number of $70/ Bbl crude by the fall, it’s a volatile world!