Tallgrass Energy’s Rockies Express Pipeline (REX) opened the floodgates for Marcellus/Utica producers this Saturday, August 1, bringing online its Zone 3 East-to-West (E2W) expansion capacity. The expansion tripled westbound design capacity to a full 1.8 Bcf/d from the Marcellus/Utica producing region to delivery points in Ohio, Indiana and Illinois. Potentially this additional takeaway capacity eases supply congestion in the Northeast and will support beleaguered Marcellus/Utica pricing points. As REX touches nearly every part of the US gas market, the expansion can ultimately be expected to reconfigure gas flows and price relationships across multiple regions as it comes online. Today we review the changes and how quickly they are likely to impact the market.
Daily energy Posts
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.
Bakken crude-by-rail (CBR) volumes are down this year and pipeline shipments are increasing as production levels off in the wake of last year’s price crash. The trend is encouraged by lower price differentials between domestic and international crude as well as new pipelines coming online. Since 2012 a combination of rail and pipeline has given Bakken producers ample crude takeaway capacity but pipelines alone have not had sufficient capacity on their own. However, with production slowing down, pipeline capacity is catching up and by 2017 there should be enough pipelines to carry all North Dakota’s crude to market. Today we start a two part series asking whether pipelines can replace CBR from North Dakota.
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.
Western Canadian Select (WCS) – the benchmark for Canadian crude sold at Hardisty in Alberta fetched just $32.29/Bbl on Friday (July 24, 2015) down 60% from $81.34/Bbl a year ago in July 2014. That year has seen big changes in the U.S. oil market with drilling rig cutbacks and declining new production rates. The challenges for Canadian producers have not changed much in the short term – with transport capacity to market still top of the list. Trouble is that every time transport congestion occurs it pushes price discounts higher and lowers producer returns. Today we discuss the relationship between Western Canadian crude production and prices.
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.
Waterborne crude shipments out of the Port of Corpus Christi are still growing this year – averaging 700 Mb/d as of May 2015. A veritable armada of barges and tankers has converged on South Texas to help move all that crude. A large part of the shipments are on small inland tank barges plying the Gulf Intracoastal Waterway (GIWW) - a 65 years old canal system that forms a vital backbone for Gulf Coast refiners. Today we describe the changing profile of barge shipments along the Gulf of Mexico.
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.
Only a few short years ago the double punch of fuel efficiency and ethanol mandates had put U.S. gasoline demand on the ropes. But in the past year demand has jumped by 0.5 MMb/d (per data from the Energy Information Administration - EIA). This surge in demand – presumably driven by cheaper prices – has kept refineries running full pelt this summer. Today we discuss the fall and rise of gasoline 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.
While Energy Information Administration (EIA) estimates of crude-by-barge traffic between the Midwest and the Gulf Coast have fallen sharply in the past 18 months, shipments down the Ohio River to Texas and Louisiana refineries have increased threefold – peaking at just under 70 Mb/d in May 2015. Growing barge shipments have been accompanied by midstream investment in barge dock facilities – especially in Ohio. Today we discuss increased shipments of ultra light crude condensate to Gulf Coast refineries on the Ohio River.
European natural gas consumers would welcome the addition of low-cost liquefied natural gas (LNG) from the U.S. to their gas-supply mix. For one thing, they want to reduce their reliance on Russia and other potentially sketchy sources of pipeline gas. For another, they want to weaken the link between oil and gas pricing—something U.S.-sourced LNG would help them do. What would it take for the U.S. to become one of Europe’s primary gas suppliers, and what would that mean for U.S. gas producers and LNG exporters? Today we continue our examination of the international LNG market with a look at what’s driving European curiosity about U.S. LNG.
In 2015 Alaskan crude has enjoyed something of a change in fortunes compared to the past few years – when shale production seemed to threaten its future. Production was up by over 50 Mb/d in the first 4 months of 2015 (according to the Energy Information Administration – EIA). The market share of Alaskan crude in West Coast refineries also crept up by 1% this year compared to 2014 at a time when crude throughput at those refineries increased. Today we discuss the changes and whether they are likely to continue.