Massive infrastructure investments in petrochemical steam crackers and export terminals for propane, butane and ethane are in the works. But the market has changed since the investment decisions for many of these facilities were made. Instead of the low ethane prices the petrochemical market is enjoying today (about 19 cents/Gal), prices could ramp up to 50 cents/Gal by 2020 as new steam crackers and ethane export facilities come online. If ethane prices increase and crude oil prices remain below $65/bbl, the feedstock cost advantage of ethane versus naphtha that the new petrochemical facilities expected likely would not materialize. Lower crude oil prices would also cap production growth of all NGLs, limiting the volumes to be exported through the new terminals. Today we review Part 2 of our Drill Down Report on NGL Infrastructure.
CME/NYMEX Henry Hub natural gas futures prices for August delivery continue to trail $1.50/MMBtu behind year-ago levels and natural gas production volumes show little sign of softening. Gas demand is rallying to record-setting levels and the balance is tightening. But there is still a long way to go before the storage inventory surplus is reined in. Today we revisit supply/demand balance and its impact on storage this summer.
Big changes are coming to the markets for natural gas, NGLs and crude oil. Even though production volumes are holding their own – despite 60% fewer rigs running, the days of month-after-month record increases in production are behind us, at least for a while. But what about all that infrastructure that has been and continues to be built? Billions of dollars are going into pipelines, processing plants, petrochemical plants, terminals, storage, etc. based on a much higher production growth scenario than now looks likely. So what happens next? That issue is the theme of a new RBN conference scheduled for July 23rd in New York City called State of the Energy Markets, and is the subject of today’s blog – also an advertorial for the conference.
Natural gas exports to Mexico are on a tear, and there’s every reason to believe the market will continue to grow. In essence, parts of the Eagle Ford and Permian Basin are becoming the go-to fuel source for new power plants and industrial facilities south of the border, as evidenced by a Howard Energy Partners plan to build new, connecting pipelines to deliver large volumes of gas directly from South Texas to emerging demand centers in and around Monterrey, Mexico. Howard’s also been addressing some of Texas’s gas gathering and processing needs. Today, we consider the latest plan to add gas pipeline capacity across the Rio Grande.
The past 10 years have been challenging, to say the least, for Western Canadian natural gas producers, and the situation may not get better any time soon. Squeezed out of many of their traditional markets in eastern Canada and the U.S. Midwest and Northeast and stymied by delays in the development of West Coast liquefied natural gas (LNG) export projects, producers in Alberta and British Columbia have been suffering from lower prices and searching for new outlets for their gas. Alberta’s oil sands and power generation sectors will help, but the big fish producers need to land is LNG exports. Today, we consider recent developments in a region long on natural gas reserves but short on gas buyers.
Asia for years has been seen as the primary market for U.S.- sourced liquefied natural gas (LNG), and that’s still true today as the first round of U.S. export facilities inch toward completion and operation. But an ongoing upheaval in the international LNG market—and the “destination flexibility” built into most U.S. LNG sales and purchase agreements--suggest that Europe may receive significant volumes of U.S. LNG as well. It’s also possible that U.S. exporters may become “swing suppliers” like LNG trading giant Qatargas, ready to direct LNG-laden vessels across either the Atlantic or the Pacific, depending on where the price is higher. Today, we continue our look at the fast-changing LNG market and what it means to U.S. natural gas producers and LNG exporters.
The biggest fundamental price indicator in the natural gas market -- Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report – is about to get a major makeover. The EIA is planning to split the US gas inventory data into five regions, from three macro regions currently. The idea has been floating out there for a while, but now it looks imminent, with a good chance it is rolled out before the gas winter season comes around in November. When it does happen, the increased granularity will vastly improve the transparency of natural gas storage inventory data on a weekly basis. But there’s another reason it will be a big deal when it happens: It will break everybody’s storage scrapes and models. Storage modelers and forecasters will have their work cut out for them. In today’s blog, we break down the upcoming changes.
If it persists, the oil price crash may have undermined many of the assumptions behind massive infrastructure investments in steam cracker plants and export facilities for natural gas liquids (NGLs). These projects expected to take advantage of booming domestic NGL production and low NGL prices relative to crude. Yet take-or-pay commitments and committed investment in plant infrastructure means they may be exposed to poor returns if crude prices remain low. Today we detail analysis in the latest RBN Energy Drill Down Report to develop NGL supply, demand and pricing scenarios.
The six liquefaction “trains” under development at Cheniere Energy’s Sabine Pass liquefied natural gas (LNG) terminal will demand nearly 4 Bcf/d of natural gas on average, the first 650 MMcf/d of that starting within a few months. And the five trains now planned at Cheniere’s Corpus Christi site—yes, now five, not three—will require another 3.2 Bcf/d. Taken together, that’s about 10% of current daily gas production in the U.S.; in other words, a monumental logistical task. Today, we start a series looking at the challenges of securing and moving huge volumes of gas to LNG export terminals, the emerging epicenters of U.S. gas demand.
As natural gas takes on an ever-expanding role in Asian energy markets, the traditional practice of sourcing liquefied natural gas (LNG) through long-term, “point-to-point” supply deals at oil-indexed prices is being challenged on several fronts. For one, U.S. exporters are linking the price of their LNG to Henry Hub gas prices. For another, Asian LNG customers, eager to reduce costs in a suddenly glutted LNG market, are working to renegotiate their oil-linked deals, and turning to the LNG spot market, where prices have been attractively low. Fast-changing market dynamics include planned gas pipelines from Siberia to China that may well make the Asian LNG market more like Europe, where LNG competes head-to-head with piped-in gas and with coal. Today, we continue our look at the changing international market and what it means for U.S. and Canadian gas producers and LNG exports.
Expectations for continuing rampant production growth for natural gas, natural gas liquids (NGLs) and crude oil have evaporated in the heat of the price melt-down. Volumes may be holding their own, even with 60% less rigs running, but the days of month-after-month record increases in production are behind us, at least for a while. But what about all that infrastructure that has been and continues to be built? Billions of dollars are going into pipelines, processing plants, petrochemical plants, terminals, storage, etc. based on a much higher production growth scenario than now looks likely. So what happens next? That issue is the theme of a new RBN conference scheduled for July 23rd in New York City called State of the Energy Markets, and is the subject of today’s blog – also an advertorial for the conference.
RBN analysis of 31 exploration and production (E&P) companies shows sharp differences between two groups of gas-weighted firms. The US diversified group is struggling to increase production, and slashing capital spending in light of weak profitability. Meanwhile, the Appalachian group is flying high as the most profitable classification in our analysis – largely as a result of slashing costs in response to weak natural gas prices. Today we wrap up our three-part analysis of U.S. E&P company’s 2015 outlook.
In just a few months’ time, it’s become easier to get regulatory approval to use unmanned aerial systems—more commonly known as drones—and the number of ways drones can be employed by the oil and gas sector has grown substantially. In fact, drones are getting involved in just about everything: geologic mapping, site surveying, methane detection, pipeline inspection—you name it. Today, we explore how drone use in the energy sector is quickly morphing from geeky to mainstream.
Asian consumers of liquefied natural gas (LNG) hope to use the current supply glut—and the start-up of U.S. LNG export facilities--to their long-term advantage. Their very understandable goal is to up-end the old market structure, which for years has had them paying far more for LNG than their Western European counterparts. How will the coming revolution affect U.S. natural gas producers and the next round of U.S. LNG export projects? Today, we continue our review of the fast-changing global market for LNG with a look at a new set of Asian LNG buyers and at the region’s fast-changing supply/demand dynamics.
Last year at this time (May 2014) the natural gas market was concerned with how depleted US natural gas storage might be by the start of the 2014-15 gas winter season. A short year later, the concern now is how full storage could get before next winter. CME/NYMEX Henry Hub natural gas futures prices for June delivery closed at 2.915/MMBtu yesterday – presumably reflecting a decidedly bearish 2015 supply/demand balance with forecasts predicting summer-ending inventory at upwards of 4.1 Tcf, which would be the highest on record. Today we provide an update on gas fundamentals.