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.
Posts from Kelly Van Hull
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.
In the Energy Information Administration’s (EIA) latest ethane production stats — for the month of May — gas plant production of ethane exceeded 1.4 MMb/d for the first time. In the same month, ethane exports also hit a record at 191 Mb/d, and ethane demand for petrochemical production — you guessed it — hit still another all-time high, topping 1.2 MMb/d. All this is just the beginning. These numbers and the throughput of any midstream infrastructure transporting or fractionating ethane will continue to increase over the next two years as new, ethane-only crackers come online, ethane rejection dwindles and overseas exports of ethane ramp up. By 2020, U.S. ethane demand is expected to reach 2 MMb/d — up by two-thirds from where it stands now. Today we continue our series on rising ethane demand, how the new demand will be met and what it all means for ethane prices.
The last couple of years have been a wild ride for the U.S. ethane market, but look out ahead. It’s going to get crazy. The onslaught of new, ethane-only crackers is upon us at the same time overseas exports are expected to ramp up. At first glance, it might appear there is enough ethane to meet all that demand, coming from molecules that today are being rejected — that is, sold as natural gas rather than liquid ethane. But the big question — will it be enough? Because not all that rejected ethane has access to pipeline capacity needed to get it to market, at least not right now. In today's blog, we begin a new series on rising ethane demand, how the new demand will be met, and what it all means for ethane prices.
During the spring, summer and fall of 2016, U.S. propane inventories grew much more slowly than they did in the same period in 2014 and 2015, in part due to fast-rising exports. The situation isn’t dire––propane stock levels are relatively high as the winter of 2016-17 really kicks in, largely because last winter was a mild one that left inventories in good shape when the 2016 stock-building period started. But even-higher exports and the possibility of a “real” winter this time around raise the specter of an especially big drop in stored volumes over the next three months. Today we assess what the combination of higher exports and even an average winter could mean for propane inventories.
The normal butane market was anything but normal the past few weeks. All’s back to square one now, but in the last week of 2016 the price for normal butane spiked to more than $1.20/gal from only $0.73/gal in November. The differential between isobutane and normal butane plummeted into record-shattering negative territory. And the margin from cracking normal butane to make ethylene and other products fell off the chart—literally, our PowerPoints had to be reworked to show how much the margin had fallen. What the heck went on there? Today, we discuss the recent upheaval, what may have caused it, and why things snapped back to normal so quickly.
U.S. propane inventories rose by an impressive 55 million barrels (MMbbl) during the spring/summer/fall of 2014, and the mild winter of 2014-15 left propane stocks at well-above-normal levels the following spring. Another impactful inventory build—53 MMbbl—occurred during 2015’s March-to-November stock-building season, leaving propane stocks at a record 104 MMbbl as the freakishly mild winter of 2015-16 started. But propane inventories grew much more slowly through the spring/summer/fall of 2016, due in part to rising exports, and—while stocks are high as this winter begins—even-higher exports and the possibility of real winter weather raise the specter of an especially big drop in stored volumes. In today’s blog we begin a series on the significance of propane inventory levels with a look at why propane stocks rose so much in the 2014 and 2015 stock-building seasons.
The ratio of NGL-to-crude oil prices looks like it will be rebounding, and over the next two or three years could rise to levels not seen since the Shale Revolution brought down NGL prices at the end of 2012, a signal that all of the new NGL-consuming petrochemical cracker projects now under construction may not be as lucrative as their developers had once hoped. Several factors are driving the ratio’s rise: increasing U.S. demand for NGLs; more exports; stubbornly low crude oil prices and a lower trajectory of NGL production growth. Today, we examine the historical relationship between NGL and crude oil prices and the reasons why that ratio may be headed back above 50%.
We are rapidly approaching September 15, when summer blend motor gasoline changes over to winter blend, allowing the increased use of high vapor pressure normal butane in the blending. However, the spread between Reformulated Blendstock for Oxygenate Blending (RBOB, the benchmark unleaded gasoline) and normal butane was down to 85 cents/gal as of the end of August, reducing the incentive to blend as much butane into motor gasoline as possible to its lowest level in recent years. Sure, 85 cents/gal is still 85 cents. But what impact might that smaller RBOB/normal butane spread and other market factors have on butane exports? Today we examine the state of the gasoline blending and normal butane markets, and the effect that current dynamics –– a gasoline glut and strong butane prices among them –– may have.
Every day, the “wet” Marcellus and Utica shale plays are producing significant volumes of ethane, all of which needs to be moved out of regional plants, fractionators and de-ethanizers immediately, either by “rejection” into natural gas or on pipelines to the Gulf Coast, Ontario, or to an export terminal in Marcus Hook, PA. A leading midstream company—MPLX’s MarkWest subsidiary—has developed an ingenious, integrated approach for handling much of that ethane (and dealing with any disruptions), but its ethane-management system is not a regional cure-all, and the likely development of an ethylene plant in the heart of the Marcellus/Utica would only increase the region’s ethane-handling needs. Today, we continue our examination of natural gas liquids (NGL) storage needs in the Northeast with a look at how nearby ethane storage might help midstream companies that are not integral parts of MarkWest’s “ethane loop.”