It’s a bit like trying to find a red bus on London’s Oxford Street when you really need one, just when the market could have done with a few extra LPG cargoes appearing from the U.S. Gulf, as well as more clarity on when new midstream and export expansion capacity was about to arrive, nothing much happened, but the clock keeps ticking, and with the blink of an eye we will be seeing in the New Year, 2020. It looks to me as if all those red buses are going to arrive pretty much all at once, but will we have enough passengers, or in our world, NGL production, to fill the bus up. And when all this is happening, exporters face a new dawn, with a new slate of different terms and conditions, shorter and fewer contracts and lower terminal fees. So, will the actions of the exporters reflect too many cooks spoiling the broth?
U.S. propane production has risen for most of 2019, but poor steam cracker economics has kept petrochemical consumption reined-in, while propane exports have been constrained by export capacity shortfalls, especially along the Texas shoreline. It’s all led to a significant build-up in propane inventories, as reported by the EIA, and not far off record levels, as the injection season came to an end. Now I’ve looked at weather maps, forecasts, and meteorological experts, and the swing of opinion is heading more to milder than normal temperatures in the U.S., despite a few bursts of cold weather in recent weeks. Draws yes, but surely these will be smaller than normal for this time of year. Not necessarily, some will say. As I stated yesterday, there’s a lot of change happening, whether it’s the supply of propane, pipeline and fractionation expansion, or simply more export terminal capacity. So, where will this leave us at the end of the winter, and for me the true beginning of the 2020 cycle.
I’ve been told that I shouldn’t get too excited about cold weather being the be all, and end all, of the U.S. winter consumption, especially in relation to the seasonal supply and demand “valve”, better known as the inventory, held in the Mont Belvieu dome storage. Instead it’s really all about the combination of rapid NGL production growth, a generally flourishing propane export market and the whims of petrochemical NGL margins, meaning we all need to keep an eye on the ARB, steam cracker economics worldwide, and crude oil prices.
EIA’s Winter Fuels Outlook, published on 8th October, has considered the warmer than average weather forecasts, and dropped consumption in the northeast and the Midwest, by 3% and 6%, when compared to last winter. But as we say, there’s more to the U.S. propane market than just the winter weather. Firstly, despite PADD 1 production continuing to grow, PADD 3 (U.S. Gulf coast), which is by far the biggest production area in the U.S., has seen a drop of over 15% since my Ibiza holiday in August. We’ll look at this in a little more detail for 2020 shortly. Secondly, propane for the last couple of months has provided better margins than both normal butane and ethane, which is the first time this has happened for a prolonged period since January 2017. This may well continue, especially with the comparative strength of normal butane at the moment. Finally, Enterprise are supposed to be adding the 175 M Bbls/d of extra export capacity, and November is certainly showing evidence of more VLGC liftings, with rumours of over 85 cargoes potentially leaving U.S. terminals, although Wednesday’s EIA numbers showed less propane exports, not more, so it’s still a debate that needs to be settled.
During the winter of 2016/17, temperatures were over 16% warmer than the average, yet propane inventories dropped by a huge 60 million barrels by the end of April 2017. It was propane exports, coupled with steam cracker consumption of propane that drove the numbers. Why wouldn’t it happen again, and weather can change at any time, maybe it will get colder again this winter. This nicely brings me to what I see as the critical period for our market next year, which is the end of the first quarter, and the beginning of the new U.S. injection season. I’ve put forward the argument as to why we might be surprised where inventory levels will end-up by the end of the winter season, but do I believe it, sorry I don’t. I think the market is going to twist and turn throughout the next 4-5 months. We’ve become too programmed that the ARB will remain open, and therefore we can all live pretty happy ever after. But we’ve seen three factors this summer stretching the ARB. Firstly there was the strength in Asia that prolonged beyond the end of winter and dragged the ARB wider at the buying end, followed by the production, inventory, export fear in Mont Belvieu pulling the sell end down in the mid part of the summer, and finally the post drone / Iran cutbacks that pushed Asia up faster than the U.S. market, which had its own impetus, but was also being dragged up by the stronger Asian buying.
But look at it now, the ARB has capitulated, losing up to $30/ Mt at the front of the curve in less than 10 trading days. Asia looks as if it is finding it hard to absorb more volumes, especially at higher prices in relation to crude, while the U.S. is showing a mini resurgence on the back of some winter demand starting to show through, petchem interest in propane and limited fractionation production skewing the purity versus Y-grade ratios. It very much looks as if the word we had started to forget, “cancellation”, could very much be back on the cards again. We still have a way to go but it’s amazing how things can quickly change; December FEI paper has a value in the very low $170s/ Mt, take freight at $130/ Mt and this leaves 8 cents/ gallon ($42/ Mt) for terminal fees. Still okay, but they’re being eroded. Then add in what is believed to be record November loadings, less butane tank nominations, and it doesn’t look rosy for the ARB continuing to remain open. We might be in for a far shakier winter ride than any of us expected.
The graph at the start of SIMON SAYS looks as if we are again going to enter a period of export over-capacity, that’s unless we see the high case scenario. But we hear in the news each week of rig counts down, and questions from Wall Street on the future access to capital for the shale producers. However, I still feel we are going to see production increasing, most likely within the high and low scenarios, as it always seems to do. It still means over capacity, in a period where long term purchase contracts are not attracting international buyers, who have been bitten once already, and they also want to see netback pricing in exchange for any long term commitment, which U.S. exporters are just not willing to agree to. The exporters goals of five-year contracts to invest in extra capacity, seems to have been replaced with actual deals for a year or less. So, although the majority of the original long-term deals are coming to an end, exporters are fairly covered into 2020, certainly for the first half of the year, but the fees are half the levels of 2015.
The real big change in the second quarter of 2020 will be the huge multi-terminal deals with the likes of ExxonMobil and Chevron, to cover each of their expanded production volumes. But, although we will be seeing production growth, it’s difficult to see it utilising all the extra capacity coming on-stream. Something looks as if it will have to give, and that looks more and more likely to be terminal fees. The mid-streamers make the money from the well-head to the dock, they have the producers locked-in on long term deals at high takeaway numbers, so all they need to do is keep the product moving. The best way to do this is to entice buyers with lower terminal fees, and it looks as if the exporters are going to be selling more and more cargoes on a short-term basis than they have since 2015. I’d be buying the first half of 2020 in the U.S Gulf and selling the second half, wouldn’t you?