As U.S. crude production ramps back up and larger volumes flow to the Gulf Coast, competition is building among midstream companies for control over the final miles from pipeline to refinery or marine dock. Nowhere is this more evident than the Houston area, where more than a dozen pipelines can deliver as much as 4 million barrels/day to the region’s 10 refineries as well as to export docks. Owners of the long-distance incoming pipelines—seeking to secure terminal, storage and dock fees—are making significant midstream investment in Houston, but smaller players are also developing assets. Today we begin a two-part series describing the build-out and how competitive the market has become.
When you examine the assets, contracts and other details of a midstream company using a fine-toothed comb, you can gain a fuller, more useful understanding of the firm’s value and growth prospects. With such a thorough analysis, one thing that becomes clear is that vertically integrated midstreamers—those with interconnected processing, pipeline, fractionation and storage assets—tend to do better than those whose facilities are scattered and disjointed. Why? Because by controlling the midstream value chain—all the way from wellhead to end-user—they flow product through multiple assets, filling capacity and gaining revenue each step along the way. Today we continue our review of highlights from a new East Daley Capital report that examines the inner workings of more than 20 U.S. midstream companies.
As natural gas exports to Mexico continue to rise and as construction proceeds on liquefaction/LNG export terminals in Freeport and Corpus Christi, TX, the need to transport increasing volumes of gas down the Texas Gulf Coast becomes ever more urgent. And moving gas down the coast is no easy task; the Lone Star State’s convoluted mix of interstate and intrastate pipelines were designed primarily to flow gas up the coast from South Texas and Gulf Coast production areas to the greater Houston Ship Channel area—and from there on interstate pipes to Louisiana and beyond. Today we use RBN’s Fretboard Model to discuss whether existing and planned southbound pipeline capacity will be sufficient to meet export demand.
Accurately assessing the value of—and prospects for—a midstream energy company requires a deep, detailed analysis that considers the firm’s individual processing plants, pipelines, storage and other assets; asset location and the degree to which the assets complement each other; and the underlying contracts that generate revenue. Do less, and you may be getting a pig in a poke. It’s true, things are definitely looking up in the midstream sector, but that hardly makes every midstream company a winner. Today, we review highlights from a new East Daley Capital report that shines a harsh, bright light on the inner workings of more than 20 U.S. midstream companies.
Earlier this month, Tallgrass Energy’s Rockies Express Pipeline (REX) achieved full in-service of its 800-MMcf/d Zone 3 Capacity Enhancement Project, boosting the line’s east-to-west takeaway capacity out of Ohio to 2.6 Bcf/d, up 45% from 1.8 Bcf/d previously. Flows since then provide early indications of how Marcellus/Utica producers and downstream markets are responding to this added ability to move gas west. In today’s blog, we continue our look at how the expansion has impacted flows, this time with a focus on the delivery side.
Fundamental changes in U.S. crude oil production, crude transportation patterns, refinery sourcing of oil, import volumes and other factors have undermined the ability of the Strategic Petroleum Reserve to mitigate the domestic impact of a world energy crisis. Worse yet, the Department of Energy’s planned fix for the SPR will take at least several years—assuming it’s allowed to proceed according to plan. Today we consider current shortfalls in the SPR’s crude-delivery network, the potential effect on U.S. refineries in the event of an emergency, and the DOE’s plan to fix things.
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.
The agreement by OPEC and several non-OPEC members to cut crude oil production by a total of 1.8 million barrels a day (MMb/d), which caused a rise in crude prices, kicked in on January 1. Now, more than three weeks in, many in the market remain skeptical that the deal will hold, and are on the lookout for the slightest hint that parties to the agreement may be—for lack of a kinder word—cheating. In today’s blog, “Won’t Get Fooled Again—Monitoring Compliance With The OPEC/NOPEC Deal To Cut Production,” we recap the agreement’s terms, examine how participating producers might try to skirt the rules, and discuss ways to check that everyone is acting on the up and up.
Plains All American Pipeline announced on Tuesday that it has agreed to acquire Alpha Crude Connector (ACC), an extensive, FERC-regulated crude oil gathering system in the Permian’s super-hot Delaware Basin, for $1.215 billion. At first glance that might seem to be a lofty price, but the development of the ACC system appears to be a classic case of right-place/right-time because it addresses a fast-growing need for pipeline capacity across an under-served area. And, with its multiple connections, ACC is an attractive source of crude to fill currently underutilized downstream pipelines headed to Midland, the Gulf Coast to Cushing. Today we review Plains’ newly announced agreement to acquire the ACC pipeline system in southeastern New Mexico and West Texas.
Tallgrass Energy’s Rockies Express Pipeline earlier this month (on January 6, 2017) brought into service the last 350 MMcf/d of its 800-MMcf/d Zone 3 Capacity Enhancement Project, boosting the line’s east-to-west takeaway capacity out of Ohio to 2.6 Bcf/d, up 45% from 1.8 Bcf/d previously. The new, fully-subscribed capacity, designed to serve Marcellus/Utica producers, filled up almost instantaneously. But unlike previous capacity additions, Northeast production did not increase. Instead the gas came from other pipelines. This development provides an early indication of what the new capacity will mean for producers, flows and prices. In today’s blog, we delve into pipeline flow data to understand the early impacts of the new takeaway capacity.
Every day, about 1.8 million barrels of NGLs, naphtha and other ethylene plant feedstocks are “cracked” to make both ethylene and an array of petrochemical byproducts. And every day, decisions are made for each steam cracker on which feedstock—or mix of them—would provide the plant’s owner with the highest margins. Within each petchem company, these decisions are optimized by staffs of analysts and technicians using sophisticated and complex mathematical models that consider every nuance of a specific ethylene plants’ physical capabilities. Fortunately for us mere mortals, it is possible to approximate these complex feedstock selection calculations for a “typical” flexible cracker using a relatively simple spreadsheet model. Today we continue our series on how the raw materials for ethylene plants are picked with an overview of RBN’s feedstock selection model, a review of feedstock margin trends, and an explanation of how the model also can be used to indicate future NGL and naphtha prices and to assess the prospects for various industry players.
While oil prices have risen in recent months, they are a far cry from the $100/bbl prices of two and half years ago, and there is certainly no guarantee they won’t fall back below $50. In other words, the survival of exploration and production companies continues to depend on razor-thin margins, and E&Ps must continue to pay very close attention to their capital and operating costs. Lease operating expenses—the costs incurred by an operator to keep production flowing after the initial cost of drilling and completing a well have been incurred—are a go-to cost component in assessing the financial health of E&Ps. But there’s a lot more to LOEs than meets the eye, and understanding them in detail is as important now as ever. Today we continue our series on a little-explored but important factor in assessing oil and gas production costs.
The capacity of a pipeline built to transport crude oil or refined products is often thought to be tied only to the pipe’s diameter and pumps, as well as the viscosity of the hydrocarbon flowing through it. Increasingly, though, midstream companies are injecting flow improvers—special, long-chain polymers known as “drag reducing agents” —into their pipelines to reduce turbulence, thereby increasing the pipes’ capacity, trimming pumping costs or a combination of the two. The role of these agents has evolved to the point that they aren’t simply being considered to boost existing pipelines, their planned use is being factored into the design of new pipes from the start. Today we begin a series on DRAs and their still-growing influence on the midstream sector.
Natural gas production from the oil- and condensate-focused SCOOP/STACK combo play in Oklahoma—one of the most productive plays in the U.S. currently—grew through 2016, even as other producing areas in the state, and in the Midcontinent as a whole, declined. As one of just a handful of locations that returning rigs are targeting, the SCOOP/STACK has the potential to single-handedly offset production declines in other parts of the U.S. Midcontinent and make Oklahoma a natural gas growth state again. Moreover, the RBN production economics model shows the natural gas output from the SCOOP/STACK has the numbers and the proximity to be directly competitive with gas supply from the Marcellus/Utica. Today, we continue our SCOOP/STACK series, with a look at the production economics driving interest in this play.
The five refineries in the U.S. Pacific Northwest (PNW) performed better in 2016 than rivals on the East Coast for two main reasons. First, the changing pattern of North American crude supply has worked to their advantage. Faced with the threat of dwindling mainstay crude supplies from Alaska, refiners in Washington State replaced 22% of their slate with North Dakota Bakken crude moved in by rail. They have also enjoyed advantaged access to discounted crude supplies from Western Canada. Second, PNW refiners face less competition for refined product customers than rivals on the East and Gulf coasts, meaning they have a captive market that often translates to higher margins. Today we review performance and prospects for PNW refineries.