Production Economics

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. 

After spending the past few years on the backburner with declining production volumes, the Haynesville Shale natural gas play, which straddles the Northeast Texas-Louisiana border, is back in the headlines. Rig counts in the region have doubled in the Haynesville in the past six months or so. Exco Resources—which has four rigs operating there currently—last week said it is divesting its Eagle Ford assets in favor of boosting drilling investment in the Haynesville. At the same time, there’s a new crop of operators in the play dedicated specifically to drilling in the Haynesville. While total basin production volumes have yet to take off, all signs point to a Haynesville resurrection of sorts. But there are also early clues that much has changed since the first go-round and the drilling profile of today’s Haynesville is likely to look much different than it did nearly 10 years ago. Today we begin a look at RBN’s latest analysis of production economics in the Haynesville Shale.

U.S. crude oil production is back above where it was this time last year—at 9.1 MMb/d, 700 Mb/d over the low point last summer. Nearly 400 Mb/d of that surge has been since end-November when the OPEC deal was announced. So, in less than four months, U.S. producers have already taken one-third of the 1.2 MMb/d market share OPEC gave up. No doubt about it: The U.S. E&P sector is back. But not because prices are above $60 or $70/bbl. Instead, this recovery is being driven by rising productivity in the oil patch. And that makes it a whole different kind of animal than we’ve seen before, with implications for upstream, midstream, downstream and just about anything that touches energy markets. That’s the theme for our upcoming School of Energy—Spring 2017—“Back in the Saddle Again—Market Implications of the 2017 U.S. Oil and Gas Recovery” that we summarize in today’s blog.

Cheniere Energy last Friday announced it has signed precedent agreements (firm capacity deals) with foundation shippers for its 1.4-Bcf/d Midship Pipeline project, which is targeted for an early 2019 in-service date. The announcement marks the latest milestone for midstream companies looking to move natural gas production from the SCOOP/STACK shale plays in central Oklahoma to growing demand markets in the Southeast and along the Texas Gulf Coast. Production from SCOOP and STACK grew by 1.0 Bcf/d, or 60%, in the past three years to 2.7 Bcf/d in 2016 and is expected to grow by another 1.5 Bcf/d by 2021. Besides Midship, there are other projects vying to move SCOOP/STACK gas to market. But how much capacity is really needed and by when? Today we look at the Midship project and its role in alleviating potential takeaway constraints.

The oil- and condensate-focused SCOOP and STACK shale plays in Central Oklahoma have been garnering the industry’s attention for their attractive producer economics, which are second only to the Permian among the crude oil shale plays. Rig additions in Oklahoma over the past several months are clearly targeting this 11-county area of the Anadarko Basin, and the RBN Production Economics Model projects production from the region will grow by 1.5 Bcf/d over the next five years. The increased drilling activity and expected production growth has piqued the interest of midstream companies looking to invest in infrastructure in the area. Given the increased output, is more takeaway capacity needed, and if so by when? Today we continue our look at the potential for takeaway constraints out of the SCOOP and STACK.

Natural gas production out of Oklahoma’s SCOOP and STACK plays has been resilient in the face of lower oil and gas prices and is expected to grow by about 1.5 Bcf/d over the next five years. But with the Marcellus/Utica increasingly competing for both pipeline capacity and demand markets outside the Northeast region, the question is where can and will the new SCOOP/STACK supply go? That will be dictated in large part by where demand is growing—primarily along the Gulf Coast—and where the price differentials are attractive. But flows also can be hindered or facilitated by another, preeminent factor:  pipeline takeaway capacity. Today we explore the potential for takeaway constraints out of the SCOOP and STACK.

Natural gas production from the oil- and condensate-focused SCOOP/STACK combo play in Oklahoma—one of the most productive plays in the U.S. currently—grew through 2016, even as other producing areas in the state, and in the Midcontinent as a whole, declined. As one of just a handful of locations that returning rigs are targeting, the SCOOP/STACK has the potential to single-handedly offset production declines in other parts of the U.S. Midcontinent and make Oklahoma a natural gas growth state again. Moreover, the RBN production economics model shows the natural gas output from the SCOOP/STACK has the numbers and the proximity to be directly competitive with gas supply from the Marcellus/Utica. Today, we continue our SCOOP/STACK series, with a look at the production economics driving interest in this play.

Drill-rig counts and crude oil production are down sharply in the Eaglebine, one of many less-than-stellar shale plays that drillers and producers have mostly abandoned in favor of superstar counties in the Permian Basin, the southern Eagle Ford and the STACK play in Oklahoma. It’s understandable; in today’s low-oil-price/high-stress environment, everyone’s chasing the sky-high initial production (IP) rates that provide the biggest, quickest returns and help pay the bills. Still, as we will discuss today, there are at least a few glimmers of hope in the Eaglebine, including a possible pipeline restart and a new pipeline tie-in that will reduce crude-delivery costs. Now all we need is $60+/bbl oil.

U.S. crude oil production is finally falling in response to the collapse in oil prices that started in mid-2014. Output is now poised to drop below 9 MMb/d--700 Mb/d off its April 2015 peak—and the rate of decline is accelerating. That raises all-important questions of how low will production go, which shale basins will be hit the hardest, and the most important question of all - how much will oil prices need to rise to reverse those declines?  Understanding the factors necessary to answer these questions is the focus of RBN’s latest Drill Down report that we highlight in today’s blog. The bottom line?  All production economics is local.

For the past, year many shale oil producers have defied the expectations of many and kept output at or near to record levels in the face of falling oil prices and much tougher economics. Improvements in productivity, cost cutting and a concentration on “sweet spot” wells that generate high initial production (IP) rates have all helped cash strapped producers survive. But with oil prices so far in 2016 stuck in the $35/Bbl and lower range and with the worldwide crude storage glut still weighing on the market – producers are finally pulling back. Today we look at how increased pressure on North Dakota producers is putting the brakes on Bakken crude production.