Natural gas production growth in the U.S. Northeast—the primary driver of U.S. production growth in recent years—has slowed dramatically in the past few months, up no more than 1 Bcf/d year-on-year, compared with growth in increments of 3 and 4 Bcf/d in previous years. Despite the slowdown, the regional balance continues to lengthen, with supply growth outpacing demand. Yet, regional gas prices, specifically at key supply hubs, which previously were struggling under the weight of oversupply coupled with limited access to growing demand markets, are strengthening. Is this the beginning of the end of takeaway constraints and distressed supply pricing in the region? Or will constraints reemerge this summer? Today, we provide an update of Northeast gas supply/demand balance.
Daily Energy Blog
As a group, the nine natural gas-focused exploration and production companies that were analyzed in our Piranha! market study are forecasting a 62% increase in capital spending in 2017 compared with 2016, a significantly higher percentage gain than their oil-focused and diversified counterparts. The driver of accelerated investment is the expected completion of natural gas infrastructure that will boost takeaway capacity from the Marcellus and Utica shales, the operational focus of eight of the nine gas-weighted E&Ps. Expanded access to Canadian, Midwestern, Gulf Coast and export markets should significantly boost realizations and margin. Production growth by the nine E&Ps, which slowed to 4% in 2016 after a 19% rise in 2015, is expected to accelerate to 10% in 2017 and to rise rapidly in 2018 and beyond. Today we continue our analysis of U.S. E&P capital spending and production trends by taking a deep dive into the investment strategies of the natural gas-weighted peer group.
In only three years, the international liquefied natural gas (LNG) market has undergone a major transformation. The old order, founded on long-term, bilateral contracts with LNG prices linked to crude oil prices, is being replaced by a more-fluid, more-competitive paradigm. That’s good news for LNG buyers, who are benefiting from a supply glut and lower LNG prices—the twin results of slower-than-expected demand growth in 2014-15 and the addition of several new liquefaction/LNG export facilities in Australia and the U.S. But the new paradigm poses a challenge for facility developers: How do they line up commitments for new liquefaction/LNG export capacity that will be needed a few years from now in a market characterized by LNG oversupply and rock-bottom prices? Today we begin a two-part series that considers the hurdles developers face and which types of projects may have the best prospects.
The Permian may be grabbing most of the energy headlines lately, but a noteworthy share of crude oil production growth the U.S. experiences over the next two or three years is sure to come from the Gulf of Mexico. There, far from the Delaware Basin land rush and the frenzy to build new Permian-to-wherever pipelines, a handful of deepwater production stalwarts are completing new wells — at relatively low cost — that connect to existing offshore platforms. Taken together, these projects are expected to increase the Gulf’s output by more than 300 Mb/d by the end of 2018. Today we look at the Gulf’s under-the-radar growth in oil output and the prospects for continued expansion there.
The techniques used to wring increasing volumes of crude oil, natural gas and natural gas liquids (NGLs) out of shale continue to evolve, and as they do, producers are facing mounting costs for securing frac sand and for disposing of produced water from the wells. These costs are squeezing producer profits, and—in an era of sustained low hydrocarbon prices—sometimes even flip production economics from favorable to unfavorable. Today we continue our surfing-themed series on sand costs and water-disposal expenses with a look at how sand use in shale plays has evolved—and how these changes affect the bottom line.
U.S. LNG exports via Cheniere Energy’s Sabine Pass LNG export facility are poised to be a major demand driver of the domestic natural gas market in 2017. Pipeline deliveries to the terminal have more than tripled since mid-2016 and are set to climb further as more liquefaction capacity ramps up. With two liquefaction trains already operational, the Federal Energy Regulatory Commission last month approved Train 3 to begin operations and also green-lighted the start-up of Train 4 commissioning. Today, we provide an update of Sabine Pass’s export activity and its potential effect on U.S. gas demand this year.
After cutting capital investment 71% between 2014 and 2016, the 13 diversified U.S. exploration and production (E&P) companies examined in our Piranha! market study are planning to increase 2017 capital spending by 30%. While this seems like a lackluster rebound compared to the 47% boost announced by oil-focused E&Ps, the diversified group’s totals are skewed by the pull-back strategy of giant ConocoPhillips. Excluding ConocoPhillips, the 12 other companies are guiding to a 48% increase in 2017 investment—very similar to their oil-weighted peers. Today we continue our Piranha! series on upstream spending in the crude oil and natural gas sector, this time zeroing in on E&Ps with a rough balance of oil and gas assets.
The Florida natural gas market will soon have access to another supply source. In June 2017, the Sabal Trail Transmission natural gas pipeline project is expected to begin service, bringing the market one step closer to connecting Marcellus/Utica natural gas to demand markets on the increasingly gas-thirsty Florida peninsula. The project will increase gas supply options for growing power generation demand in the Sunshine State while effectively also increasing gas-on-gas competition between producers in the Northeast, Gulf Coast and Midcontinent. Today we provide an update on Sabal Trail and its related projects.
In the past few years, producers in shale and tight-oil plays have made great strides in reducing their drilling costs and improving the productivity of their wells. But the trends toward much longer laterals and high-intensity well completions have significantly increased the volumes of sand being used—some individual well completions use enough sand to fill 100 railcars or more! An even bigger concern for many producers is the rising cost of disposing of produced water—that is, the water that emerges with hydrocarbons from these supersized wells. Today we begin a surfing-themed series that focuses on how the two key components of any beach vacation—sand and water—are impacting producer profitability.
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.
Crude oil prices are up more than $5/bbl over the past couple of weeks, mostly due to Middle East tensions and the latest readings of OPEC tea leaves. U.S. markets have contributed little to the bullish trend, with crude oil inventories hanging in there at 533.4 million barrels, just under the all-time record hit last week. U.S. production is up almost 800 Mb/d since the low last summer and a whopping 550 Mb/d since the OPEC/NOPEC deal. That’s some decidedly bearish statistics. If these trends hold, the U.S. could completely offset the 1.2 MMb/d in OPEC production cuts in another six months. But that begs the questions, where exactly do these statistics come from, and how should they be interpreted? The first answer is simple: it is the U.S. Energy Information Administration. But where do they get the numbers? And what can we learn about the crude oil market through a better understanding of the sources and assumptions behind these numbers? That is our topic in today’s blog.
The 21 oil-focused U.S. exploration and production companies examined in our Piranha! market study are planning an average 47% increase in their 2017 capital expenditures and expecting a 7% increase in production. The 47% boost in capex is huge, but due to draconian cuts in 2015 and 2016 this year’s total is still off 58% from 2014’s—an indication of the big hole the sector is still climbing out of. The Permian Basin continues to attract more capital—no surprise there—but capex in the Bakken is also on the rise after a few lean years. Today we continue our Piranha! series on upstream spending in the oil and natural gas sector, this time zeroing in on E&Ps that focus on crude.
Energy Transfer’s latest Texas-to-Mexico natural gas pipeline project—the 1.4-Bcf/d Trans-Pecos Pipeline—began service a little over a week ago (on March 31, 2017). It’s the third Tejas-to-Méjico gas transportation project to come online in the past six months, following the expansion of ONEOK’s Roadrunner Gas Transmission pipeline in October 2016 and the in-service of Energy Transfer’s Comanche Trail Pipeline in January 2017. The three projects have added a total of nearly 3.0 Bcf/d to pipeline export capacity since last October, all originating in the Permian Basin at the Waha gas trading hub in West Texas. A game-changer, right? Well, the reality is not so simple. These expansions on the U.S. side are largely reliant on takeaway capacity on the Mexico side of the border as well as the growth of power demand downstream to support flows, not all of which is coinciding with capacity additions on the U.S. side. Today we look at the latest export pipeline capacity additions and prospects for near-term export demand growth along the Texas-Mexico border.
The build-out of Houston-area crude oil storage and marine terminal capacity continues, and as it does, ship congestion in the Houston Ship Channel worsens. Which raises the question, why not develop more crude storage and marine docks outside the Ship Channel that still offers strong pipeline connectivity to crude production areas, the Cushing hub and Houston-area refineries—plus easier access to the open waters of the Gulf of Mexico? That’s a key premise behind Oiltanking’s first major Gulf Coast expansion since the February 2015 sale of most of Oiltanking’s assets in the region to Enterprise Products Partners. Today we discuss Oiltanking’s plan to add crude storage and a marine terminal in Texas City, TX.
Rising natural gas exports from South Texas and increasing production of “associated” gas in the Permian Basin are driving the development of several new gas pipelines from West Texas to the Agua Dulce gas hub and nearby Corpus Christi. The age-old questions apply: How much new pipeline capacity will be needed, and how soon? The construction of these new pipelines also raises the question of how a potential flood of new gas supply from the Permian to the South Texas coast might affect plans by others to flow gas down the coast from Houston. Today we continue our look at proposed gas pipelines from the Permian to Agua Dulce and Corpus Christi with a review of two more projects and their potential impact.
