Exploration and production companies (E&Ps) in shale basins have a water problem — in fact, they have three water problems. Two are upfront well-completion costs: sourcing water for the frac job and disposal of the flowback water from the frac job. These are nontrivial issues, but they pale in comparison to a much bigger problem – produced water – the water that always comes along with the oil and natural gas out of a well. It is a lot of water; on average in the U.S., somewhere around five to six barrels of water are produced for every barrel of oil that comes out of the ground, more from some basins than others. The Permian, for example, produces six to eight barrels of water per barrel of crude. That’s over 1,000 Olympic-size swimming pools full of water out of the Permian alone each day. And because this water is chock-full of minerals, petroleum residue and especially salt (which makes it brine), producers must dispose of the water in a safe, environmentally responsible manner. They are doing that today. But what happens if Permian production doubles — a distinct possibility. Today we continue our surfing-themed series on the effect of sand and water costs on producer economics with a focus on produced water in the U.S.’s hottest shale play.
Daily Energy Blog
After posting significant pretax operating losses in 2015-16, U.S. oil-weighted exploration and production companies returned to profitability in the first quarter of 2017. The 180-degree turnaround in peer group results was driven not only by higher oil prices, but by major strategic and operational shifts. Most of the 21 E&Ps we’ve been tracking responded to the plunge in revenue that started nearly three years ago by optimizing their portfolios, shedding properties with higher breakeven costs to focus on core unconventional plays and implementing operational efficiencies that led to sharply lower drilling and completion costs. Today we discuss how, with higher cash flows and profits, crude oil producers are ramping up their 2017 capital spending to generate long-term production growth.
By the early 2020s, crude oil flows from the Permian to Corpus Christi are likely to increase by at least several hundred thousand barrels a day and may well rise by more than one million barrels a day. That can only happen, though, if new pipeline capacity is in place to move crude from West Texas to the coast and if enough crude-related infrastructure — storage, distribution pipelines, marine docks, etc. — is developed in Corpus to receive, move and load all that oil. Docks and ship-channel depth are particularly important; the bigger the vessels that Corpus marine terminals can handle, the more competitive Permian crude will be in far-away markets like Asia. Today we continue our series on the build-out of crude infrastructure in South Texas’s largest port and consider Corpus’s ability to load Suezmax-class vessels and maybe even Very Large Crude Carriers (VLCCs).
For years now, U.S. Northeast natural gas production growth has been paced by the availability of pipeline takeaway capacity out of the Marcellus/Utica shales. Midstream companies have been racing to build the infrastructure to support drilling and rising supply in the region. And, until now, it was safe to assume that as new pipeline projects come online, volumes would grow to fill them in short order. But over the next couple of years, that may flip: takeaway capacity additions could soon outpace supply increases, and producers might not be able to keep up. Today, we provide an update of RBN’s Northeast gas production scenarios.
Midstream giant Enterprise Products Partners, with a market capitalization of $57 billion, has attracted significant investor interest because of its simplified structure, 51 consecutive quarters of dividend growth and strong distribution coverage — $2.7 billion in retained cash in the last three years. The company has continued to build out its large integrated midstream network despite the plunge in commodity prices, investing almost $18 billion in organic growth projects and acquisitions in 2014-16. Enterprise (NYSE: EPD) is now connected to every major U.S. shale basin, every U.S. ethylene cracker and 90% of the refineries east of the Rocky Mountains. As a result, it is well positioned to benefit from the recovery in crude oil and natural gas production, especially in the Permian and the Eagle Ford; continuing NGL and crude oil exports; and the impending growth of the U.S. petrochemical industry. Today we discuss highlights from the first part of our new Spotlight analysis of EPD, which focuses on the company’s NGL Pipelines & Services segment.
Faced with uncertain growth in demand for refined products in the U.S., at least five refiners with major U.S. operations — including majors Shell, BP and Chevron — joined the bidding at a recent auction offering access to Mexico's downstream distribution system. Energy market reforms now unraveling national oil company Petróleos Mexicanos’ domestic supply monopoly are providing this opportunity. Initial auction winner Tesoro gained storage and pipeline capacity in two states in northwestern Mexico it expects to supply from a Washington state refinery. The market reforms also extend to retail gasoline stations, and majors BP and ExxonMobil as well as Valero and international trader Glencore have recently announced plans to launch retail networks in Mexico. Today we review the access Tesoro won in the first logistics auction as well as the wider Mexican market opportunity for refiners with operations north of the border.
A record amount of natural gas supply — close to 8.0 Bcf/d — from the Marcellus and Utica shale plays is making its way to the broader U.S. market. That’s happened with the help of a substantial build-out of pipeline infrastructure to reverse gas flows out of the now oversupplied Northeast, which has allowed regional production to grow to nearly 23 Bcf/d from less than 8 Bcf/d five years ago. One of the major target markets for this gas has been the Midwest. About a third of current outbound flows is heading to the Midwest, primarily via the reversal and expansion of Tallgrass Energy’s Rockies Express Pipeline, completed earlier this year. Moreover, midstream companies are due to install an additional 5.5 Bcf/d or so of takeaway capacity to target the Midwest and Canada by late 2020, with 70% of that due this year alone, starting with Energy Transfer’s Rover Pipeline. However, many of these expansion projects have been embattled by regulatory, environmental and political hurdles during the approval process. Today we provide an update of Rover and other Midwest- and Canada-bound takeaway projects.
From an expenditure perspective, the refining side of the U.S. oil sector couldn’t be more different from the exploration and production side. Sure, both demand a lot of capital, but while E&P companies’ capex can ramp way up or way down year-to-year, reflecting shifts in hydrocarbon supply, demand and (mostly) pricing, refiners’ spending tends to be more consistent over time. Refiners focus primarily on maintaining existing assets and on making the incremental enhancements needed to refine new grades of crude, to expand refining capacity and to comply with ever-tightening environmental regulations. Today we review historical capital spending by a few of the largest refining companies in the U.S. and examine several of the larger projects where refiners’ dollars are being invested today.
Crude oil exports out of Corpus Christi have increased sharply in the past few months, hitting a record 11.5 million barrels (MMbbl) in April 2017. And that may be just the beginning; the volume of crude put on ships in the Shining City by the Sea is likely to rise new Permian-to-Corpus pipeline capacity is completed and as new storage capacity, distribution pipes and marine docks being planned to accommodate a flood of Permian oil come online. Today we continue our series on the build-out of crude-related infrastructure in South Texas’s largest port and refining center with a look at rising crude exports and the new projects being planned.
Plans for LNG export terminals, petrochemical plants and gas-fired power generation along the Gulf Coast have made it the #1 target market for Marcellus/Utica natural gas producers. At the same time, these demand projects along the coast, from the Southeast, Texas and even farther down in Mexico, are counting on more supply growth from Appalachia. Since 2014, close to 5.0 Bcf/d of southbound pipeline capacity has been added and another 4.0 Bcf/d is due by early 2019. Today, we continue our update of pipeline expansions out of Appalachia, this time with a focus on the Ohio-to-Gulf Coast corridor.
The accelerating trend toward high-intensity completions in the Permian, SCOOP/STACK, Marcellus/Utica, Haynesville and other key shale plays is sharply increasing demand for frac sand. As a result, there's upward pressure on sand prices and there are shortages of certain grades of sand that may continue into 2018. There is also increased interest in developing sand mines near production areas. It’s important to remember, though, that (1) there’s no evidence that sand-supply issues will seriously curtail drilling and completion activity, and (2) higher sand costs can be offset by the production gains that usually come from using a lot more sand. Today we continue our surfing-themed series on sand costs and water-disposal expenses with a look at the forecast for 2017-18 demand for frac sand, sand pricing trends, efforts to develop regional sand supply sources and the bottom-line upside of high-intensity completions.
Today OPEC convened in Vienna, expecting to extend production cuts for another nine months beyond June 30. Both the OPEC and NOPEC countries have generally kept to their commitments since January, which has been extremely good news for U.S. producers; they are enjoying higher prices, steadily improving economics and above all, the opportunity to capture market share from OPEC/NOPEC. Since the deal was announced this past November, U.S. production is up 600 Mb/d — about half of OPEC’s promised 1.2 MMb/d cut — and at this rate U.S. producers will have grabbed all of OPEC’s forgone market share by the end of the year. Put simply, the U.S. has taken on a leading role in international oil markets, and as a result it’s now more important than ever to understand on a more granular and real-time level what’s going on in U.S. crude production, imports, exports and inventory. In today’s blog we examine how U.S. producers have been profiting from OPEC/NOPEC efforts to curtail worldwide supply and prop up prices, and how RBN’s new weekly report, “The Gusher,” tracks the key factors affecting U.S. crude.
Higher crude oil and natural gas prices, improved efficiency in drilling and completion and other factors combined to give most U.S-based exploration and production companies (E&Ps) solid financial results in the first quarter of 2017 — a stark contrast to their performance in 2015 and 2016. Better yet, the turnaround is providing E&Ps with the optimism and wherewithal to significantly ramp up their planned capital spending this year and in 2018. It’s also giving them an opportunity to zero in on shale plays with low breakeven costs that will help them maintain profitability even if commodity prices stay flat or sag. Today we analyze the first-quarter financial results of a group of 43 U.S. exploration and production companies.
Over the past five years, the Corpus Christi area’s ability to refine or ship out crude oil has increased substantially, driven initially by rising production in the Eagle Ford play in South Texas — growth that has since subsided. Now, Corpus is preparing for a coming onslaught of crude from the red-hot Permian, whose producers see the coastal port as the preferred destination for their light crude and condensates. Today we continue a blog series on Corpus Christi’s crude-related infrastructure with a look at what’s already there and how storage and marine-terminal upgrades made over the past few years will be coming in handy.
One of the major target markets for Appalachian natural gas is the U.S. Southeast. More than 32 GW of gas-fired power generation units are planned to be added in the South-Atlantic states by 2020 and LNG exports from the Southeast are increasing. Of the 15.5 Bcf/d of takeaway capacity planned for Appalachia, close to 5 Bcf/d is targeting this growing demand. Despite the need, these pipeline projects designed to increase southbound flows from the Marcellus Shale have faced regulatory delays and setbacks. Today, we provide an update on capacity additions moving gas south along the Atlantic Coast.
