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.
On Friday, TransCanada finally secured a Presidential Permit for the U.S. portion of its Keystone XL pipeline, and the company committed to pursuing the state approvals it still needs to build the project. But three hard truths—crude oil prices below $50/bbl, the high cost of producing bitumen and moving it to market, and more attractive energy investments available elsewhere—have thrown a wet blanket on once-ambitious plans to significantly expand production in Western Canada’s oil sands, the primary source of the product that would flow through Keystone XL. Today we begin a series on stagnating production growth in the world’s premier crude bitumen area, the odds for and against a rebound any time soon, and the need (or lack thereof) for more pipelines.
According to Energy Information Administration data, the 26 refineries in the Midwest/PADD 2 region processed an average 3.6 MMb/d of crude oil in 2016—up 300 Mb/d from the 3.3 MMb/d refined in 2010. Over the same six-year period, production of light oil production in the region shot up by over 1 MMb/d, mostly from the prolific Bakken formation in North Dakota. Yet Midwest refiners did little to take advantage of the sudden abundance of “local” production, increasing instead their appetite for imported heavy crude from Western Canada by nearly 1 MMb/d—from 800 Mb/d in 2010 to 1.8 MMb/d in 2016. Today we explore the trend for PADD 2 refineries to run more heavy crude even as shale output surged in their backyard.
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.
The ability to increase the capacity of existing and planned crude oil pipelines with minimal capital expense has genuine appeal to midstream companies, producers and shippers alike. Enter drag reducing agents: special, long-chain polymers that are injected into crude oil pipelines to reduce turbulence, and thereby increase the pipes’ capacity, trim pumping costs or a combination of the two. DRAs are used extensively on refined products pipelines too. Today we continue our look at efforts to optimize pipeline efficiency and minimize capex through the expanded use of crude-oil and refined-product flow improvers.
Five years ago, the U.S. was a net importer of propane and butanes, those products collectively called LPG, or liquefied petroleum gasses. Back then, demand from residential, commercial, refining and chemical markets slightly exceeded supply for the products. But then came shale, and LPG production from natural gas processing more than doubled, from 0.8 Mb/d to 1.7 Mb/d. Suddenly the U.S. was a net exporter—a very big exporter at that. Last year roughly half of all LPG from U.S. gas processing plants was exported, with the vast majority shipped to overseas markets. All those exports are now having an outsized impact on pipeline flows, inventories and prices. Consequently, it is increasingly important to keep close tabs not only on export volumes but on which export terminals are handling all these volumes, and where the LPG is heading. Today we discuss the current state of the LPG export market and insights on it from RBN’s most recent NGL Voyager Report. Warning, today’s blog includes a subliminal promo for the report.
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.
Last week, crude oil prices dropped below $50/bbl, in part due to continued increases in U.S. crude oil inventories, and fell further over the next few days. Then yesterday, prices perked up by $1.14 to $48.86/bbl; again one of the factors was the weekly inventory number from the Energy Information Administration which showed inventories down by a fraction of a percentage point for the week. The market seems to react spontaneously to changes in that crude-stocks statistic. Up is bearish, down is bullish. These days even a very modest decline in inventories is bullish. But serious analysis requires a more detailed, more nuanced understanding of why crude oil inventories behave as they do. Were inventories driven up by higher production or lower refinery runs? By higher imports? By lower exports? The reasons behind the inventory change are more important than the change itself. Today we continue our series on the modeling of U.S. crude oil supply and demand, and the sourcing of input data used in those calculations.
New International Maritime Organization rules slashing allowable sulfur content in bunker fuels come January 2020 are expected to be a boon to complex refineries with coking units that can break residual high-sulfur fuel oil (HSFO) into low-sulfur middle distillates and other high-value products. The IMO rules also are expected to undermine the already shaky economics of many simpler refineries that don’t have cokers and are therefore left with a lot of residual HSFO. Today we conclude our blog series on the far-reaching effects of the new cap on bunker fuel sulfur content with a look at how the IMO rules will create winners and losers among refineries, and improve diesel refining margins.
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.
The latest sharp drop in crude oil prices, which was blamed in part on unexpected gains in already record-high U.S. inventories, is a stark reminder of the importance of understanding and routinely calculating estimates of the oil supply/demand balance. Only by keeping up with the ever-changing relationship between crude availability and crude consumption—and by anticipating shifts in that relationship—can oil traders and others whose daily success or failure depends on crude pricing trends make informed decisions. Today we begin a blog series on the modeling of U.S. crude oil supply and demand, and the sourcing of input data.
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.