The prospects for sellers of Williston Basin/Bakken crude oil in what once was a prime growth market—the U.S. East Coast—have been dwindling fast, as have the volumes of Bakken crude being railed and barged to refineries along the Mid-Atlantic coast and the Canadian Maritimes. Today we look at how a combination of weak crude oil prices, declining production, high relative freight costs, and the lifting of the U.S. crude oil export ban have opened the door to more imports from West Africa, and left Bakken producers out in the cold.
For the first time since the start of the crude-by-rail (CBR) boom a few years ago, just as much crude oil is being transported by rail to PADD 5—that is, to states in the western U.S.—as to the Eastern Seaboard states in PADD 1. This primarily reflects the facts that 1) CBR deliveries from the Williston Basin/Bakken to PADD 1 continue to plummet and 2) refineries in the West remain reliable buyers of railed-in crude from the Bakken and Western Canada. Will CBR shipments to the East Coast continue to fall, or have we seen the worst of the decline? Today we take a look at recent trends in crude movements by tank car, and a look ahead.
More midstream projects than you might expect are “goin’ on” in the Western Canadian province of Alberta, considering the challenges that bitumen/crude oil and natural gas producers there continue to face. There are several drivers behind the relatively long list of oil and diluent pipelines; gas processing plants and fractionators; and oil/NGL storage facilities being built in Canada’s Energy Province, but much of the work is being done to meet the expected needs of oil-sands expansion projects approved during better times and set to come online soon. Today we begin a blog series on Alberta midstream projects with an overview of where the province’s energy sector stands today.
The ratio of NGL-to-crude oil prices looks like it will be rebounding, and over the next two or three years could rise to levels not seen since the Shale Revolution brought down NGL prices at the end of 2012, a signal that all of the new NGL-consuming petrochemical cracker projects now under construction may not be as lucrative as their developers had once hoped. Several factors are driving the ratio’s rise: increasing U.S. demand for NGLs; more exports; stubbornly low crude oil prices and a lower trajectory of NGL production growth. Today, we examine the historical relationship between NGL and crude oil prices and the reasons why that ratio may be headed back above 50%.
More than four years after the Utica and the “wet” part of the Marcellus became a hot spot for drillers, the field condensate and natural gasoline produced there are still moved to market by barge, rail and truck. A three-part, $500 million plan by MPLX LP and the midstream master limited partnership’s (MLP’s) subsidiaries, now well under way, will enable more efficient pipeline transport of these important hydrocarbons to Midwest refineries, Western Canadian diluent pipelines and other end-users. To hold down costs, the effort involves a creative mix of new and existing pipelines. Today we continue our review of MPLX’s plan with a look at its “Utica Build-Out Projects.”
Net crude oil imports to the U.S. Gulf Coast in 2016 have been running well above the pace set last year, the increase driven by a combination of lower U.S. crude oil production, rising import levels and relatively flat export volumes. The trend toward higher net imports –– an outgrowth of the end of the ban on U.S. crude exports –– is significant in that it affects oil inventories and oil prices. What’s driving this trend, and how soon might net imports peak? Today, we survey recent developments on the crude oil import/export front, with a focus on the Gulf Coast.
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.
The group of 21 liquids-focused exploration and production companies we have been tracking plans to cut capital expenditures by half in 2016, after a 42% decline in 2015. However, capex for this “oil-weighted” E&P peer group is apparently bottoming out—their mid-year guidance was only 2% lower than their original 2016 estimates. Even with deep cuts in capital spending, the group expects production to fall only 7% in 2016, and those estimates have been revised higher from the initial 2016 guidance. Also worth noting: Pure Permian Basin players, the most optimistic companies in the peer group, are cutting capital spending by only 19% and are expecting a 12% gain in production. And with Apache Corp.’s announcement earlier this week of a huge discovery in the Permian’s Southern Delaware Basin, the market is definitely making a turn. Today we discuss 2016 capex and production for a representative group of E&P companies whose proved reserves are more than 60% liquids.
Enable Midstream Partners stands at a crossroads. It has great assets –– natural gas gathering and processing operations in the Anadarko, Arkoma, and Ark-La-Tex basins; a crude oil gathering system in the Williston Basin; and interstate/intrastate gas pipelines that ship natural gas from its gathering regions to the Texas Panhandle and Illinois. The company also has an excellent position in gathering systems and processing plants in the prolific STACK and SCOOP plays in Oklahoma. But everything is not rosy. Earnings from STACK/SCOOP are being offset by production declines in its other areas of operation. On top of that, CenterPoint Energy, which owns 55.4% of Enable’s limited partnership units, is seeking to divest its shares, which would bring a new majority owner into the picture. In today’s blog we review our latest Spotlight analysis.
The Shale Revolution sparked a multibillion-dollar re-plumbing of the U.S. crude oil pipeline network that continues to this day, two years after oil prices started falling and one year after oil production volumes followed suit. While the pace of development has at times seemed hectic, the individual decisions to build new pipelines involve a lot of studying, vetting and number crunching. After all, pipelines don’t come cheap, and their success depends to a considerable degree on their long-term usefulness to the market. One of the most important factors in determining whether a crude oil pipeline project makes sense is its capital cost and, with that, the cost of moving oil through it. Today, we continue our look at crude pipeline economics with a discussion of the basics of estimating pipe size and cost, and figuring the optimal capacity of a given pipeline project.
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.
Way back when—before 2012—few outside a small cadre of oil producers and marketers paid any attention to condensates, or even knew they existed. Then two events shook the condensate world. First came rapid growth in the Eagle Ford, where crude oil production turned out to be almost half condensates. Then the Department of Commerce started allowing condensate exports while maintaining the ban on international sales of mainstream crude oil. Suddenly condensates were the star of the show. But like the careers of one-hit rock & roll wonders, the stardom didn’t last long. The crude oil price crash hit Eagle Ford hard, resulting in a disproportionate decline in condensate production. Congress then sent condensates further back into obscurity by removing the export ban for all crude oil in December 2015, eliminating any special status for the product. That was the end of the road for the condensate story, right? Wrong. Because during condensate’s day in the sun, billions were spent on pipelines, stabilizers, splitters, export facilities and refinery modifications, all focused on providing new markets for condensates. Oops. Today we consider how the next chapter of the condensate saga will play out.
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.
In their second quarter 2016 earnings announcements, North American exploration and production companies (E&Ps) announced relatively minor changes to the steep reductions in 2016 capital budgets they unveiled around the first of the year. Total 2016 “finding and development” spending for 46 leading U.S. producers was an estimated $41.0 billion, down 51% and 70% from investment in 2015 and 2014, respectively, and slightly lower than the $41.9 billion forecast for 2016 spending in year-end 2015 announcements. The second-quarter reports over the past few weeks also confirmed the initial guidance of a 4% production decline in 2016 after 7% and 6% increases in 2014 and 2015. However, as we discuss today, a look behind the headline numbers indicates that cuts in capital expenditures (capex) look to have bottomed out, and that the industry may be poised for a turnaround in drilling activity later this year into 2017.
Eight years into the Shale Revolution –– and two years into a crude oil price slump that put the brakes on production growth –– midstream companies continue to develop new pipelines to move crude to market. As always, the aims of these investments in new takeaway capacity may include reducing or eliminating delivery constraints, shrinking the price differentials that hurt producers in takeaway-constrained areas, or giving producers access to new markets or refineries access to new sources of supply. Whatever the economic rationale for developing new pipeline capacity, midstreamers and potential crude oil shippers need to examine–– early on –– the likely capital cost of possible projects, if only to help them determine which projects are worth pursuing, and which aren’t. Today, we begin a series on how midstream companies and potential shippers evaluate (and continually reassess) the rationale for new crude pipeline capacity in today’s topsy-turvy markets.