A proposed BASF plant in Freeport, TX - that would make propylene from natural gas – is expected to be the subject of a final investment decision in 2016. If the plant is built it will have a similar purpose to another 6 Gulf Coast plants being built or planned in the next few years to make propylene from propane. All these plants are designed to make up for lower propylene output from U.S. petrochemical steam crackers using ethane, which yields less propylene from the cracking process. Today we discuss why using natural gas as a feedstock instead of propane might make sense.
The CME/NYMEX Henry Hub natural gas futures contract turns 25 years old this year. The contract is now the third largest physical commodity futures market in the world. The price of virtually every Btu of gas sold in North America is linked in some way to the underlying physical hub at Henry. But over the past five years shale gas has revolutionized North American supply and changed the shape of delivery patterns. These trends have altered the flow of physical gas through Henry Hub and could jeapordize the success of the futures contract. Today we look at why Henry Hub has been so successful.
How the international market for liquefied natural gas (LNG) expands and evolves is of critical importance to U.S. and Canadian natural gas producers and midstream companies alike. The success of North American-sourced gas in penetrating LNG demand centers--Asia and Europe in particular—will help determine not only how much gas needs to be produced, but how much incremental pipeline and liquefaction/LNG export capacity needs to be developed, and how much upward pressure there will be on U.S. and Canadian natural gas prices. There is a lot of uncertainty about how things will shake out. Today, we conclude our series with an assessment of what we know, what we aren’t sure about, and what we think we’re likely to see happen.
A few years ago, water-based or “hydraulic” fracturing emerged as a viable, cost-effective technique for coaxing large volumes of natural gas and crude oil out of U.S. shale formations. Calling it a game-changer is not an overstatement. In the shadows, another approach to fracturing was being developed, one that uses a liquefied petroleum gas (LPG) or propane gel and appears to offer some noteworthy benefits over tried-and-true hydraulic fracking. Today, we consider the potential for niche applications (and maybe much more) for fracturing that’s based on a hydrocarbon-based gel—not water.
The Henry Hub in Louisiana is the best known natural gas trading location in the world. There is certainly no more liquid point in the industry. An average of 350,000 Henry Hub natural gas futures contracts trade on the CME/NYMEX each day. The Henry price is used to compute locational ‘basis’ at all other natural gas trading points in North America and thus is the reference price for tens-of-thousands of derivative instruments and other commercial contracts. But the U.S. natural gas industry is changing rapidly. Henry started out as a supply market hub but a natural gas demand renaissance in and around Louisiana is transforming it into a demand market hub. How will this impact Henry and can/will it endure as the national benchmark price? Today, we begin an in-depth series looking at Henry Hub, starting with its origins.
The start-up of Sabine Pass, the first liquefied natural gas (LNG) export terminal in the Lower 48, is only months away, and the complicated gas-delivery logistics behind the project are coming into focus. Surely one of the biggest challenges has been assembling the long-haul pipeline capacity needed to move several billion cubic feet of gas a day (Bcf/d) to Sabine Pass from deliberately diverse sources as far away as the Marcellus/Utica. After all, the nation’s pipeline network was initially designed to move gas from the Gulf Coast to the Northeast and Midwest, not vice versa. Today, we continue our look at the challenges of securing and moving huge volumes of gas to LNG export terminals, the emerging epicenters of U.S. gas demand.
Analyst estimates for this week’s Energy Information Administration (EIA) Weekly Natural Gas Storage Report before its release were rallying around an expectation of a 95-Bcf injection, according to the Wall Street Journal’s survey of storage analysts. The actual number reported by EIA yesterday (July 16, 2015) was a 99-Bcf injection, more or less in line with analyst expectations. But predictions may get a bit harder later this year. The EIA is preparing to redraw its US natural gas storage map and begin reporting inventory data in new regions later this year (2015). In August, prior to the launch of the revamped report, it will release a file with historical data for each of the new regions. The historical data will for the first time allow modelers to run their regressions and gather statistical information by which to rebuild their storage models designed to foretell the weekly EIA storage number. In the meantime, we did our own unscientific analysis of the regional breakdown and how it will change transparency in gas storage activity. Today, we examine storage capacities in the old versus new regions and potential impact on analyst visibility.
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.