Adapting to a new era of low crude oil and natural gas prices, U.S. exploration and production companies, have been reconfiguring their portfolios to focus on a small group of shale plays whose production economics can hold up even through tough times. Among the largest producers, no company is a better example of this trend than Anadarko Petroleum, which has sold over $12 billion in assets since the beginning of 2014—including properties that generated one-third of its 2016 production—to focus 80% of its capital investment on just three U.S. plays. Since year-end 2013, Anadarko has lowered its net debt by 16%, or $8 billion, and it exited 2016 with over $8 billion in liquidity. The company forecasts 15% compound annual production growth through 2021 at current prices, with the liquids weighting of output increasing from 44% in 2015 to 65% in 2021. Today we zero in on one of the 43 E&Ps whose new-era strategies are detailed in RBN’s new Piranha! market study.
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.
Despite OPEC’s production cuts, crude oil prices are still hovering just below $50/bbl, and there are certainly no guarantees that they won’t fall back to $40 or lower (at least for a while). So the survival of many exploration and production companies continues to depend on razor-thin margins, meaning that E&Ps need to trim their capital and operating costs to the bone. Lease operating expenses—the costs incurred by an operator to keep production flowing after the initial cost of drilling and completion—are a go-to cost component in assessing the financial health of an E&P. But there’s a lot more to LOEs than meets the eye, and understanding them in detail is as important now as ever. Today we continue our series on the little-explored but important topic of lease operating expenses.
U.S. oil and natural gas exploration and production companies, anticipating continuing low crude oil and natural gas prices, have been reshaping their portfolios to focus on a half-dozen top-notch resource plays whose production economics can hold up even through the roughest of patches. The biggest of these asset purchases and sales grab the headlines, but countless other, smaller deals are having profound effects too. Taken together, this piranha-like devouring of E&P assets in the Permian Basin, SCOOP/STACK and other key production areas is transforming who owns what in the plays that matter most, and positioning a select group of E&Ps for success. Today we review highlights from “Piranha!” —a just-released market study from RBN.
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.
South Texas is emerging as the newest premium destination for natural gas supply in the U.S. Demand in the area is expected to grow much faster than local production, creating a supply shortage in the region by early 2018. New pipeline capacity will be needed to move incremental supply into South Texas. There are several projects planned to facilitate southbound capacity on pipelines running along the Gulf Coast Industrial Corridor. Today we examine the planned pipeline capacity and whether it will be enough to serve the coming demand.
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.
U.S. natural gas exports drove a significant portion of overall gas demand growth in 2016 and are expected to continue being the primary demand driver over the next several years. Much of this export demand will be emerging along the Texas-Mexico border and at planned LNG export terminals along the southern Texas Gulf Coast. But production in the South Texas region is not expected to grow nearly as quickly or robustly as demand, setting the stage for supply constraints and premium pricing in the South Texas market and making the area a target destination for producers and pipeline companies. For example, on Wednesday, Enterprise announced the possibility of a new pipeline from Orla, TX, in the Permian Basin to Agua Dulce in South Texas. So how will all of this play out? Today, we continue our series analyzing the gas supply and demand balance in South Texas, this time with a look at the demand side and the resulting market balance.
Last year was the best for global LNG demand growth since 2011, and a combination of ample LNG supply, new buyers and relatively low prices suggest that demand will continue rising at a healthy clip in 2017. That’s good news not only for LNG suppliers, but for natural gas producers and for developers planning the “second wave” of U.S. liquefaction/LNG export projects. Before those projects can advance, the world’s current—and still-growing—glut of LNG needs to be whittled down, and nothing whittles a supply glut like booming demand. Today we discuss ongoing changes in the LNG market and how they may well work to the advantage of U.S. gas producers and developers.
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.
There is a premium natural gas market developing in South Texas, where exports to Mexico could rise by more than 2.0 Bcf/d over the next four years and gas liquefaction and LNG export facilities are expected to add another 1.8 Bcf/d of demand to the market in that time. While gas production from the nearby Eagle Ford Shale is showing signs of at least a partial comeback and will help meet some of this new demand, the South Texas market may be heading toward being short supply in the next few years, resulting in higher prices there relative to surrounding markets. That would make the South Texas market an attractive destination for supply as far north as the Marcellus and Utica shales. In fact, there is a slew of proposed southbound pipeline projects extending deep into Texas along the Texas Gulf Coast for shippers to get their gas there. But how much incremental supply will be needed to balance the market? Today we begin a series analyzing the gas supply and demand balance in South Texas, starting with prospects for production growth out of the Eagle Ford Shale.
The production economics of the crude oil-focused SCOOP and STACK plays in central Oklahoma are among the best anywhere—in fact, only the Permian Basin’s numbers outshine them. But, as in the Permian, crude production in SCOOP and STACK can only grow if sufficient midstream infrastructure is in place to process and take away all of the associated natural gas the wells there produce. Processing and takeaway constraints aren’t big issues in SCOOP/STACK yet, but they will be soon. Today we discuss highlights from RBN’s new Drill Down Report on production growth and looming infrastructure constraints in two of the U.S.’s most promising shale plays.
A number of indicators suggest that the energy slump that started in the latter half of 2014 has bottomed out, and that happy days are here again (at least for now). Who would have thought back in the good ol’ days three years ago this month—when the spot price for crude oil was north of $100/bbl and the Henry Hub natural gas price averaged $5.15/MMbtu—that Friday’s $54 crude and $2.63 gas would be seen as anything but a catastrophic meltdown. But not so. The fact is that in 2017, producers in a number of basins can make good money at these price levels. Consequently, drilling activity is coming on strong. Crude oil production is up more than 500 Mb/d since October 2016 to 9 MMb/d, a level not seen in almost a year. And gas output has also been poised to rise, if only real winter demand had kicked in this year. What’s going on? Today we discuss the fact that what we have here, folks, is a rebound unlike any we’ve seen before.
The March 2017 CME/NYMEX Henry Hub natural gas futures contract has shed nearly 60 cents/MMBtu (17%) since February 1, 2017, and the rest of the 2017 curve has been slashed by an average 40 cents (12%) in that time. On February 1, prices for all 10 remaining 2017 futures contracts (from March to December 2017) carried $3 handles. Now, all but two contracts are below $3. Weather has been the primary driver of this shift. February 2017 is set to rank as the warmest February since 1970, after January 2017 also came in as one of the warmest in 40 years. Weather forecasts are also showing the warmth extending into March. These developments are signaling a more bearish 2017 than expected. Today, we continue our supply and demand update with a look at the 2017-to-date balance.
The SCOOP and STACK plays in central Oklahoma have emerged as two of the most productive and cost-effective plays in the entire U.S. Rigs are returning, crude oil production is rising, and so is production of associated natural gas. Moreover, the RBN production economics model shows that SCOOP and STACK will continue to be attractive to drillers under all of our various price scenarios—even if crude were to slip back below $50 and natural gas goes back into the dog house, where it has been headed the past few days. Today we continue our look at the side-by-side Sooner State plays with a review of existing and planned gas processing capacity.