Corpus Christi, TX, is quickly becoming a strategic hub for U.S. crude oil exports. Since the repeal of the crude oil export ban in December 2015, crude exports from the Sparkling City by the Sea have increased to nearly 500 Mb/d — and that may be just the beginning. Numerous pipeline and terminal projects have been announced to receive, store and ship out a lot more crude from the Permian and Eagle Ford shale plays, with an increasing share of those barrels destined for the international market. Today, we discuss recent developments in crude exports out of South Texas.
Posts from Amy Kalt
Over the past few years, rising production in the Canadian oil sands and U.S. shale plays such as the Bakken, Permian and Eagle Ford has given refiners new options for sourcing their crude, causing changes in oil pipeline utilization and prompting the development of new pipelines — or the reversal of existing pipes. A prime example of all this is playing out in Memphis, TN, where a Valero Energy refinery will be shifting from mostly U.S. Gulf Coast-sourced light crude to light crude that will flow in on the new Diamond Pipeline from the Cushing, OK, crude storage hub. Valero’s change in crude sourcing will be yet another blow to the 1.2-MMb/d Capline Pipeline, which for decades has moved crude north from the Gulf Coast to Patoka, IL, and other points along the way, including western Tennessee. Today, we look at the thinking and economics behind Valero’s plan and at the latest news on Capline.
Since last winter, the price gap between light crude oil and heavy crude — otherwise known as the light-heavy differential — has narrowed considerably. In February, the price difference between Louisiana Light Sweet crude (LLS) and heavy Maya crude on the Gulf Coast was almost $10/bbl, providing an advantage to refiners who have invested in cokers and other equipment that allows them to run a heavier crude slate. But since June Maya has on average sold for only about $5/bbl less than LLS. Today we examine the shrinking price gap between light and heavy crude and its effect on coking and cracking margins.
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.
Worldwide, refiners expect to add significant capacity over the next five years, mostly in the Middle East and the Asia Pacific region. While only a small amount of crude processing capacity additions are expected in the U.S. and Canada, the capacity additions elsewhere could have major product-trade and utilization effects on U.S. refiners — especially in PADD 1 (East Coast). Today we analyze expected near-term refinery capacity additions, global demand projections, and potential effects in the U.S.
From an expenditure perspective, the refining side of the U.S. oil sector couldn’t be more different from the exploration and production side. Sure, both demand a lot of capital, but while E&P companies’ capex can ramp way up or way down year-to-year, reflecting shifts in hydrocarbon supply, demand and (mostly) pricing, refiners’ spending tends to be more consistent over time. Refiners focus primarily on maintaining existing assets and on making the incremental enhancements needed to refine new grades of crude, to expand refining capacity and to comply with ever-tightening environmental regulations. Today we review historical capital spending by a few of the largest refining companies in the U.S. and examine several of the larger projects where refiners’ dollars are being invested today.
A major component of the formula used to set the price of Maya—Mexico’s flagship heavy crude, and a key staple in the diet of many U.S. Gulf Coast refiners—was changed earlier this month, raising new questions about this important price benchmark for nearly all heavy sour crude oil traded along the U.S. Gulf, and points beyond. The change came as Maya production volumes continue to fall, and as Maya is facing increasing competition from Western Canadian Select (diluted bitumen) from Western Canada. Today we conclude a two-part series on Maya crude oil, the new price formula and its potential effects.
Maya, Mexico’s flagship heavy crude, has been a key staple in the diet of U.S. Gulf Coast refiners for a long time, and it has faithfully served as a price benchmark for nearly all heavy crude oil traded along the U.S. Gulf, and points beyond. Maya’s price, relative to lighter benchmark grades such as Louisiana Light Sweet (LLS) or Brent, provides ready insight into the profitability of heavy oil (coking) refiners. But production of Maya peaked in 2004 and has declined considerably since then, raising questions about its continuing efficacy as a price benchmark. Now it’s come to light that a component of the Maya price formula was changed effective January 1, 2017. Although the change—related to the formula’s fuel oil price component—might be viewed as a relatively minor tweak, it raises new questions about this important heavy oil price benchmark. Today we begin a two-part series on Maya crude, the new price formula and its potential effects.
On November 17, 2016, Tesoro Corp., the second-largest independent refiner in the Western U.S., announced an agreement to acquire Western Refining for an estimated $6.4 billion. This is the second acquisition that Tesoro has made this year, following the purchase of the MDU Resources/Calumet Specialty Products Partners’ joint venture refinery in North Dakota. And—ironically, considering the name of the company Tesoro is buying—the Western Refining deal will expand Tesoro’s footprint further east than ever. Today we evaluate the legacy assets of Tesoro and Western Refining and discuss how the two companies will likely fit together.
Over the past few weeks, publicly traded independent refining companies reported their latest quarterly results, and nearly all lamented on a common theme: the cost of Renewable Identification Numbers (RINs) is out of control. However, the financial burden is not felt equally across the industry, as companies with integrated marketing operations (refining, blending and retailing) don’t face the same RINs-cost albatross as merchant refiners who don’t have retail operations. Today we review the escalating RIN costs that obligated parties have endured this year and explain how the degree of financial pain depends on the level of refiners’ downstream integration.
New “Tier 3” requirements to limit sulfur content in gasoline are set to take effect in just over two months — on January 2017. In March 2013, the Environmental Protection Agency (EPA) proposed to limit the sulfur content of gasoline produced or imported into the U.S. to no more than 10 parts per million (ppm) from the current “Tier 2” 30 ppm standard by January 1, 2017. With these upcoming “Tier 3” requirements, refiners have been developing their strategies to meet the regulations and in some cases have already invested hundreds of millions of dollars in their facilities. Today, we look at the various approaches refiners can take for compliance and their impacts on the industry.