Production of natural gas liquids in the Permian is growing so quickly that within a year or two some parts of the super-hot play may experience NGL takeaway constraints. That is good news for the owners of the eight existing NGL pipelines out of the Permian, which are likely to see flows on their pipes increase as NGL production rises — assuming, that is, that they have capacity to spare and that they are connected to natural gas processing plants within the faster-growing parts of the region. Today we continue our blog series on Permian NGL production, processing and pipelines with a look at ONEOK’s West Texas LPG Pipeline and the Chevron Phillips Chemical EZ Pipeline.

Nearly two-thirds of the effective NGL pipeline takeaway capacity out of the Permian is controlled by Energy Transfer Partners and DCP Midstream. But there are several other NGL pipelines used to flow Permian NGLs to faraway storage facilities and fractionators — assuming, that is, that their natural gas processing plants are connected to the pipe alternatives in question. Today we continue our blog series on the NGL side of the Permian with a look at Enterprise Products Partners’ Chaparral and Seminole pipelines and Enterprise’s and BP’s Rio Grande Pipeline, including the volumes of NGLs that have been flowing through them.

Associated natural gas production from North Dakota’s oil-focused Bakken Shale is rising as rigs are being added in the region. Bakken gas output reached a record 1.18 Bcf/d this past May. The incremental gas production in the area is intensifying competition with imports from the already-beleaguered Western Canadian Sedimentary Basin (WCSB), which share the same pipeline capacity and target the same Midwest demand markets. The trend also is prompting calls for more pipeline capacity out of the Bakken. How much more capacity is needed and by when? Today, we look at existing natural gas takeaway capacity and flows out of the Bakken.

The year-ago completion of Energy Transfer Partners’ Lone Star Express NGL pipeline from West Texas to the Mont Belvieu storage and fractionation hub near Houston was a big deal. The new, 533-mile pipe increased effective NGL takeaway capacity out of the Permian by more than 25% and gave Energy Transfer a larger conduit for moving NGL produced at its Permian natural gas processing plants directly to the company’s still-growing complex of fractionators in Mont Belvieu. Energy Transfer also owns another big NGL pipeline out of the Permian: the Lone Star West Texas Gateway. Today we continue our blog series on the NGL side of the Permian with a look at what is currently the biggest fish in the play’s NGL pond.

Production cuts by Saudi Arabia and other OPEC producers have had a profound effect on Asian refiners’ crude oil procurement by opening the door to more U.S., Canadian and North Sea crude deliveries to the Far East and South Asia. Of the four major Asian refining countries, China has seen the largest drop in imports of East of Suez crude, which includes oil produced in the Middle East, the Asia-Pacific region, Australasia and far-east Russia, but India, Japan and South Korea have experienced declines as well. What’s going on? And what does it mean for Atlantic Basin crude producers? Today, we discuss recent changes in global crude price differentials and Asian crude import slates, which include more imports from the U.S.

Over the past five years, the price differential between regular and premium gasoline has been widening steadily.  According to the Energy Information Administration (EIA), as of July 2017 the premium -vs.-regular differential reached $0.53/gallon — more than double the differential in 2012. This has produced cringe-worthy experiences at the pump for consumers requiring the premium grade and an incentive for refiners to optimize the gasoline pool.  Consequently, refiners have been making operational adjustments and capital investments to squeeze additional high-octane components out of their feedstocks. Today we examine the premium-regular gasoline differential, provide a primer on gasoline blendstocks and octane levels, and discuss some contributing factors to the widening divide between the pump prices of 87- and 93-octane gasoline.

For as long as producers have been drilling in the Bakken Shale — the oil-rich formation straddling North Dakota and Montana (plus Saskatchewan and Manitoba in Canada) — associated natural gas, an inherent byproduct, has taken a back seat to crude oil production from the play. In fact, at one point nearly 50% of Bakken’s produced natural gas was being flared, in large part due to limited midstream capacity to gather, process and move the gas to market. But that’s changed in the past couple of years. Substantial midstream capacity has been built. Flaring has eased considerably, and with the shift in drilling activity to the best, most productive acreage, the gas-to-oil output ratio has increased. Add to that rising rig counts and productivity gains in those sweet spots and that phenomenon becomes amplified. The result is that while oil production has largely stagnated this year below peak levels, associated gas volumes from the play climbed to a record high this past May. But will this trend be sustained, and, if so, what will it mean for gas flows, takeaway capacity and gas-on-gas competition at the Canadian border? Today, we begin a blog series looking at gas production trends in the Bakken and implications for gas pipeline flows as well as competing supplies.