RBN Energy

Two new 50-Mb/d, Kinder Morgan-owned and -operated condensate splitters came online during the first seven months of 2015, backed by a 10-year BP commitment to process a total of 84 Mb/d through the units. Located in the Houston Ship Channel’s refinery row, the splitters were expected to provide a profitable outlet to process growing volumes of the ultra-light crude oil known as condensate. Instead, average plant throughput through July 2016 has been only 71% of capacity, well below the 90% average operating level of neighboring refineries. The relatively low level at which these units have been operating reflects sagging condensate processing margins. Today, we detail how Kinder Morgan’s new splitters have been run during their first year or so of operation.  

MPLX LP and the midstream limited partnership’s subsidiaries (collectively referred to as “MPLX”) are stepping up to address a lingering hydrocarbon-delivery issue in the Utica and “wet” Marcellus plays, namely, how to more efficiently transport the field condensate and natural gasoline produced there to refineries, Western Canadian heavy-crude shippers and other end-users. Currently, condensate and natural gasoline are moved within and out of production areas in eastern Ohio, northern West Virginia and western Pennsylvania via truck, rail or barge. MPLX’s three-part, $500-million plan, the first elements of which are nearing completion, is mostly about pipelines—a mix of new ones and creatively repurposed existing ones. It looks like a win-win for condensate and natural gasoline producers and buyers. Today we begin a series on improving the flow of these two close relatives in the hydrocarbon family to buyers in the Midwest and beyond.

Western Canada has extraordinary oil and natural gas resources, but producers there have been suffering from a long list of woes. Oil sands producers need higher oil prices to justify expansion projects, and face shortfalls in pipeline takeaway capacity to refineries in Eastern Canada and export markets on both coasts. Natural gas producers can move gas east, but face stiff competition from the Marcellus and Utica plays; meanwhile, their efforts to expand LNG exports from British Columbia have been stymied by the new glut in worldwide LNG supplies and low LNG prices. Today we discuss the challenges in advancing Canadian oil and gas infrastructure projects.

There is a story behind every new crude oil pipeline built to supply a decades-old refinery. After all, the refinery surely had a well-established crude-delivery system in place –– why change horses now, especially with refinery margins under so much pressure? Typically, the answer is that, well, times have changed. Or, more specifically, the Shale Revolution has up-ended traditional crude sourcing, forced refinery owners to rethink their crude slates, and opened up opportunities to access new, lower-cost oil. Today, we continue our look at these new pipeline connections, their rationales, and their effects on other pipelines, barge deliveries and crude-by-rail.

The 450-Mb/d Dakota Access Pipeline (DAPL) has broken away from the pack of out-of-the-Bakken crude takeaway projects. On August 2, Enbridge Inc., through its master limited partnership Enbridge Energy Partners, agreed to take a large stake in DAPL from Energy Transfer Partners (ETP) and Sunoco Logistics Partners (SXL), a move that suggests Enbridge’s own 225-Mb/d Sandpiper Pipeline may drop out of the race soon. Joining Enbridge in the $2 billion deal is Marathon Petroleum, its former joint venture partner and anchor shipper on Sandpiper. Today, we consider these recent developments in the long-running effort to transport North Dakota crude oil to market more efficiently.

Three months after a series of devastating wildfires wreaked havoc in Alberta’s oil sands region, production is essentially back to normal. Temporary shutdowns at several production sites initially reduced the oil sands’ output by more than 1 MMbbl/d –– or about one-third the area’s pre-fire production level –– which trimmed inventories and goosed world oil prices. But the short-term closures appear to have had little effect on the Canadian and U.S. refineries that process oil sands-sourced crude. Now, oil sands producers (stung more than many by the collapse in oil prices) are focused again on reducing production costs in an effort to stay profitable in a low-oil-price era. Today, we summarize the current, post-wildfires state of oil sands production and consider the region’s future in the new, tight-oil/Shale Revolution world.

With crude storage tanks along the U.S Gulf Coast nearly full, the nine storage terminals currently operational in the Caribbean offer an advantageous close-by alternative. Right now these terminals are heavily used by Venezuela for oil blending and distribution, but there has been growing interest and investment from outside the region. China is now neck and neck with the U.S. as the world’s largest crude importer and is making a significant strategic investment in Caribbean storage to cement crude supply deals with Latin American producers. Private equity fund ArcLight Capital and trader Freepoint Commodities together purchased a huge terminal and shuttered refinery in the U.S. Virgin Islands in January of this year (2016) and have leased most of the working storage to Chinese-owned Sinopec. Today, we examine the growing role of Caribbean crude terminals. (This blog is based on Morningstar’s recently published Caribbean Crude Storage Outlook [1], which provides a comprehensive analysis of this evolving market.)