The SCOOP and STACK plays in central Oklahoma have emerged as two of the most productive and cost-effective plays in the entire U.S. Rigs are returning, crude oil production is rising, and so is production of associated natural gas. Moreover, the RBN production economics model shows that SCOOP and STACK will continue to be attractive to drillers under all of our various price scenarios—even if crude were to slip back below $50 and natural gas goes back into the dog house, where it has been headed the past few days. Today we continue our look at the side-by-side Sooner State plays with a review of existing and planned gas processing capacity.
Posts from Housley Carr
Anticipating renewed growth in natural gas and natural gas liquids production in the Marcellus and Utica plays, midstream companies active in the region are planning new gas processing plants and fractionators, as well as new NGL takeaway capacity and in-region NGL storage. And Shell Chemicals has made a Final Investment Decision to build a $6 billion, ethane-consuming steam cracker in western Pennsylvania by the early 2020s. In today’s blog, “Unleashed in the (North)East—New Gas Processing and Fractionation Capacity in Marcellus/Utica,” Housley Carr continues our series on on-going efforts by midstreamers and others to keep pace with NGL growth in the epicenter of U.S. gas and NGL production.
The Shale Revolution has caused big changes in U.S. crude oil production, in domestic flows of crude via pipelines, ships and rail tankcars, and in crude import volumes. Flow changes in particular have negatively affected the Strategic Petroleum Reserve’s ability to accomplish its two primary goals: protecting U.S. refineries from the worst effects of a major crude oil supply interruption, and—when called upon by the International Energy Agency—quickly injecting large volumes of crude into global markets. A fix now in the works would add Gulf Coast marine terminals dedicated specifically to moving SPR-stockpiled crude to those who need it, both within the U.S. and overseas. Today we conclude a two-part blog series on challenges and coming changes at the SPR.
Natural gas production in the Marcellus and Utica plays is projected to rise by 30% or more by 2022 under all of RBN’s forecast scenarios, and production of Northeast natural gas liquids is expected to increase even more quickly. Midstream companies are responding to this next phase of gas/NGL growth with plans for still more gas-processing plants, fractionators, NGL storage facilities, and NGL takeaway capacity––pipeline, rail, ship and barge. Also, Shell Chemicals continues to advance plans for an ethane-consuming steam cracker in Beaver County, PA, and another petrochemical company may soon decide to build a cracker in Ohio. Today we begin a new series on the latest push by midstreamers to keep pace with NGL growth in the epicenter of U.S. gas and NGL production.
Evaluating midstream companies—their assets, their value, their prospects—is a complicated task. It’s not enough to rely on the public face that companies put forward; typically, they highlight their strengths and minimize their weaknesses. To gain a fuller understanding of midstreamers, you need to poke around, consider their individual assets, and assess the status and outlook of the various production areas they serve. Asset location matters for a lot of reasons, but mostly because midstream infrastructure serving a thriving basin—the Permian and Marcellus, for instance—will contribute a lot more to a company’s bottom line than assets serving an area in steep decline. Today we conclude a blog series that highlights key takeaways from East Daley Capital’s new, detailed assessment of more than 20 U.S. midstream companies.
So far, relatively mild weather this winter has insulated New England natural gas consumers from pipeline capacity-related price spikes that occurred during cold snaps in previous winters. And even if another polar vortex were to happen, it’s likely the regional electric grid operator’s Winter Reliability Program to shift gas-fired generators from pipeline gas to stockpiled oil or LNG would keep the lights on. But New England’s day of reckoning is coming. The region is becoming ever-more dependent on gas-fired power, most gas pipeline projects into New England are stalled or scrapped, and New York’s recently announced plan to close two Indian Point nuclear units will only make matters worse. Today we discuss the still-widening gap between Northeast pipeline capacity and gas demand.
As natural gas exports to Mexico continue to rise and as construction proceeds on Texas liquefaction/LNG export terminals, the day is approaching when Texas will flip from being a net producing region to being (with exports) a net demand region. Fortunately, supplies from elsewhere are readily available to meet that demand—sourced from the Marcellus/Utica and moving on new and reversed pipeline capacity to the Gulf Coast. A good portion of that gas must traverse “miles and miles of Texas” to meet the burgeoning export demand at the Agua Dulce hub near Corpus Christi, a location that is emerging as a key pricing point for the South Texas gas market. But a potential problem is looming: There may not be enough pipeline capacity available to meet that demand, with important implications for South Texas prices, flows and natural gas export volumes. The average annual basis at Agua Dulce could increase to as much as a dime ($0.10/MMbtu) above Henry Hub in 2020 from its historical level $0.02/MMbtu to $0.05/MMbtu below Henry. Today we discuss these and other highlights from the fourth and final part of RBN’s Drill Down series.
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.
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.
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.
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.
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.
The recently announced combination of DCP Midstream LLC and DCP Midstream Partners LP creates the nation’s largest natural gas processor and natural gas liquids producer at what may be a particularly opportune time. The newly formed DCP Midstream LP, operating as a master limited partnership, owns 61 gas processing plants with a combined capacity of 7.8 Bcf/d—enough to process more than 10% of current U.S. production—as well as 12 fractionation plants, 59,700 miles of gas gathering pipelines and 4,600 miles of NGL pipelines. Better yet, many of these assets serve some of the U.S.’s most prolific and promising production areas, including the Midland and Delaware basins within the Permian; the Denver-Julesburg (DJ); and the side-by-side SCOOP and STACK plays. In today’s blog, we review the combined entity’s assets and prospects for growth in what soon may be happier times for NGL processors.