Production of natural gas liquids in the Permian has been increasing rapidly, especially in the Delaware Basin, challenging the region’s existing NGL pipelines and other infrastructure and accelerating the development of new capacity. The Permian already had a substantial amount of NGL pipeline capacity in place before the region’s production of crude oil and associated gas took off, and more has been added since. But a number of the NGL pipes out of the Permian also move barrels from other basins, either inbound flows from the Rockies or volumes added downstream of the Permian in the Eagle Ford and Barnett shales. In addition, the vast majority of the Permian’s incremental NGL production is occurring in the Delaware, which had only a limited number of pipes and suddenly needs more. And one more thing: fast-rising ethane demand from new petrochemical plants along the Gulf Coast will reduce the share of ethane that is “rejected” into Permian natural gas. In today’s blog we discuss the NGL takeaway challenges facing producers and processors in cowboy country.
The new, larger locks along the Panama Canal have been in operation for almost two years now, enabling the passage of larger vessels between the Atlantic and the Pacific. The timing couldn’t have been better — when the expanded canal locks came online in June 2016, exports of U.S. LPG, crude oil, gasoline and diesel were about to take off, and Cheniere Energy had only recently started shipping out LNG from its Sabine Pass export terminal in Louisiana, with Asian markets in its sights. Hydrocarbon-related transits through the canal soared through the second half of 2016, in 2017 and so far in 2018. But the gains are mostly tied to LPG and LNG — even the expanded canal isn’t big enough for the Very Large Crude Carriers (VLCCs) favored for Gulf Coast-to-Asia crude shipments, or for fully laden Suezmax-class vessels. And there already are indications that the canal’s capacity may not be sufficient to meet future LNG needs. Today, we consider the expanded canal’s current and future role in facilitating U.S. hydrocarbon exports.
After years in the doldrums, ethane prices are increasing, not so much in absolute terms, but where it counts — relative to the price of natural gas. That means less ethane will be rejected — sold as natural gas — and more will be recovered as liquid ethane and sold as a petrochemical plant feedstock. As still more new ethane-only petrochemical plants come online over the next couple of years, ethane demand will increase, boosting ethane prices and resulting in still less ethane rejection. Does that mean ethane rejection will be a thing of the past? No, not even close. U.S. natural gas production, especially gas with a high ethane content, is growing so fast that ethane supply will continue to outstrip demand for the foreseeable future, with important consequences for ethane prices. Today, we continue our review of NGL market developments.
Increasing production of NGL-packed associated gas in the adjoining SCOOP, STACK and Merge plays in central Oklahoma and rising interest in the Arkoma Woodford play in the southeastern part of the state are spurring a bevy of natural gas-related infrastructure projects. New gas-gathering systems are being developed, new gas processing capacity has come online, and at least another 1.1 Bcf/d of processing capacity is under construction or will be soon. To help bring all the resulting gas and NGLs to market, new takeaway pipeline capacity out of Oklahoma is being planned too. Today, we continue our review of ongoing efforts to add gas-processing and takeaway capacity in the hottest parts of the Sooner State.
Could it get any worse? Possibly, but the last time we saw petchem margins this bad was in the depths of the 2008-09 economic meltdown, and back then the atrocious margin levels resulted in drastic plant curtailments and in some cases permanent shutdowns. But this time around the petchem industry is in the process of bringing on even more capacity! Is the current situation a fluke, or a harbinger of things to come? In today’s blog we examine recent trends in steam cracker margins, by far the largest demand sector for natural gas liquids (NGLs) and consider what these developments may mean for NGL markets in general, and ethane in particular.
With U.S. NGL production hitting a record high of just over 4.0 MMb/d in the fourth quarter of 2017 and ethane production also reaching record volumes at 1.6 MMb/d, the price for ethane has remained stuck at about 25 c/gal — where it’s been for the past two years, even though prices for other NGLs are up over the same period. The combination of roaring high-ethane-content Permian and SCOOP/STACK NGL volumes, coupled with steam cracker outages and construction delays due to Hurricane Harvey, have landed us here. So where do we expect the ethane market to go now as incremental cracker and export demand ramp up in 2018 and 2019? Today, we continue a series on our updated NGL market forecast, highlighting the NGL product whose market is going through the most changes: ethane.
In recent weeks, both crude oil and natural gas production have breached all-time records. So it should come as no surprise the same thing happened to NGLs — production blasted to over 4.0 MMb/d in the fourth quarter of 2017, and by our estimates will move considerably higher this year. This is a particularly big deal for the ethane market, which has spent the last eight years waiting patiently for a wave of new Gulf Coast ethane-only petrochemical plants — a.k.a. “steam crackers” — to come online in 2018. Well, here we are in 2018 and new demand from the crackers is finally kicking in. The good news for petchems is that all of the incremental NGL production means the supply of ethane available to the market is growing too, right on cue. What do these developments mean for future NGL production, demand and prices? Today, we begin a new blog series discussing our updated NGL market forecasts, starting with that NGL product whose market is going through the most changes: ethane.
With ethane prices remaining below 30 c/gal, making it only slightly more valuable than natural gas at Henry Hub on a Btu equivalence, most natural gas processors/producers can earn a greater profit when ethane is sold with natural gas (rejected) than when it is extracted and sold with the NGLs. How much more money you may be wondering? The answer is — it depends. Are there downstream pipeline contracts and sunk costs impacting the decision making? Are the contracted volumes on an ethane-only pipeline or a raw mix pipeline? How far away is the producing basin from the Gulf Coast market? How do all these factors come together to determine whether ethane is produced or rejected and the value created? Today, we continue our discussion of the MQQV gas processing model — this time focusing on the Value principle. This is our final blog focusing on the MQQV model and, with it, we are making it available to all Backstage Pass holders should you want to run scenarios of your own.
It was a wild ride for Asian butane in 2017, driven by a range of diverse market factors, including U.S. ethane and LPG exports, a government program in India to encourage switching from firewood to LPG, the OPEC/NOPEC crude oil production cuts and LPG contract pricing set by Saudi Arabia. It was a textbook example of how today’s energy markets are buffeted by changes in production trends, government intervention and the growing influence of exports. Today, we introduce a series on the supply and demand dynamics that shaped Asian butane markets in 2017, and that will drive LPG markets in Asia, Europe and the U.S. in coming years.
There has been growing concern regarding NGL pipeline takeaway capacity out of the Williston Basin and the Niobrara — particularly the DJ Basin — over the past year, with one of the major pipes through those regions now running full. Finally, ONEOK has announced plans for the Elk Creek Pipeline, which will have an initial capacity of 240 Mb/d and be expandable to 400 Mb/d. The new pipe will transport mixed, unfractionated NGLs from eastern Montana to the Conway/Bushton fractionation hub in central Kansas, and provide long-term relief for a lot of Bakken, Powder River and Denver-Julesburg (DJ) Basin producers. But with an end-of-2019 in-service date, will the new capacity come soon enough to avert NGL takeaway constraints? Today, we discuss the Elk Creek project, the flows on existing NGL pipes to Conway/Bushton, and the growing significance of ethane as pipelines fill.
Prices for heavy NGLs (propane, butanes, natural gasoline) have been rising fast since the middle of 2017, but the same cannot be said for the price of ethane. For most natural gas processors/producers, low ethane prices mean that ethane continues to be worth more when sold with natural gas (rejected) than when it is extracted and sold with the other liquids. But as NGL production continues to grow, hitting a record-high 3,968 Mb/d in October 2017, and new steam crackers are just starting to come online, there is a limit to how much ethane can be left in the residue gas stream without violating dry gas pipeline Btu specifications. How do processing plant designs, gas pipeline specs and economics play into a gas processor’s decision regarding whether to extract or reject ethane? Today, we continue our discussion of RBN’s MQQV gas processing model — this time focusing on the Quantity and Quality principles.
NGL prices have been rising fast since the middle of this year, but the same cannot be said for the price of natural gas. So how does this market scenario play out for gas processors who make their money extracting NGLs from gas? It plays out pretty darn good. In Part 1 of this series, we looked at how the relationship between the price of NGLs versus natural gas can be assessed by the Frac Spread, and concluded that things are definitely looking up for gas processing economics. But we also concluded that the Frac Spread misses the impact of a few key factors, including the BTU value and composition of the inlet gas stream. So today we’ll see what it takes to incorporate those factors into our assessment and, in the process, do a deep dive into the math of gas processing to examine the relationship between volumetric capacity, gallons of NGLs per 1,000 cubic feet of natural gas (GPMs) and moles. Today, we continue our latest expedition into the wilds of gas processing.
Not long after crude oil prices crashed in 2014, natural gas processing economics hit the skids. From late 2014 through the first half of 2017, times were tough for natural gas processors and the producers processing natural gas to extract NGLs in their plants. That’s because the per-MMBtu price difference between natural gas prices and NGL prices was low. Very low. In fact, during 2015-16, it was the lowest it’s been over the past decade except for a brief period during the 2009 financial meltdown. But things are looking up. Thanks to a big boost in from propane and butane prices — and, to a lesser extent, rising ethane and natural gasoline prices — natural gas processing economics look healthier today than they have in years. It is going to get even better as more new ethane-only steam crackers come online. Given these developments, it is clearly time for another deep dive into what makes gas processing economics work, and how the numbers are about to change. Today, we begin our latest expedition into the wilds of gas processing.
Available ethane in the Marcellus/Utica is expected to increase 70% by 2022 to 800 Mb/d, from about 470 Mb/d this year. That should be good news for the slew of ethane-only steam crackers coming online in that time frame, primarily along the Gulf Coast. But unfortunately, there is limited ethane pipeline takeaway capacity out of the region and today more than half of the potential ethane supply is being rejected into the natural gas pipeline stream. Without additional takeaway capacity, that rejected volume is expected to grow and few additional ethane barrels will make their way to the Gulf Coast. The question is, will transportation economics support additional pipeline development to where the demand is growing the most? Today, we will explore how the changing ethane market is likely to impact the Marcellus/Utica producing region.
As new ethane-only steam crackers come online and ethane exports accelerate, ethane demand is ramping up from 1.3 MMb/d today to somewhere between 2.1 and 2.3 MMb/d in 2022. The good news is that a lot of new ethane supply is becoming available — from high-Btu Permian associated gas, more gas from other oil-focused plays, and of course rapidly growing Marcellus/Utica production. Depending on what happens to oil and gas prices, somewhere between 2.5 and 3.2 MMb/d of “potential” ethane could be available by 2022 to meet that demand. So, no problem, right? Not so fast. Some of this potential ethane will be very expensive to get to market, and some won’t be able to get to market at all due to pipeline capacity constraints. How these market dynamics play out raises the possibility of wide swings in ethane prices. Today we will explore how this may play out.