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.
Posts from Housley Carr
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.
It hasn’t been widely reported, but during cold snaps in late fall and early winter, a number of crude oil producers in the Permian Basin have faced a “perfect storm” of events that made it challenging to meet crude pipelines’ vapor pressure standards. At first glance, this may seem like a problem for “the technical folks” to deal with, but in fact the issue has been affecting the ability to move crude to market, and the price of oil at Midland, TX versus the crude hub at Cushing, OK. It has even forced Permian producers to “shut in” some crude production—at least for a time—along several major pipelines in the region because they’ve been unable to adequately prepare their crude for piping or trucking. Today we examine an under-the-radar problem that’s been vexing producers in the U.S.’s leading crude oil play, and affecting oil prices and markets.
The Shale Revolution has had a profound impact on U.S. NGL markets by vastly increasing production and by lowering NGL prices relative to the prices of crude oil and natural gas. That has been good news for the nation’s steam crackers, the petrochemical plants that have enjoyed low NGL feedstock prices since 2012. But NGL markets are in for some big changes as new U.S. steam crackers coming online over the next two years will be competing for supply with export markets, raising the specter of higher NGL prices—a good thing for NGL producers, but not so for petrochemical companies. How this plays out will be determined by the feedstock supply decisions petrochemical producers make as NGL prices respond to rapidly increasing demand. Today we begin a series on how steam cracker operators determine day-by-day which feedstocks are the most economic, and on the factors driving the value of ethylene feedstock prices.
The build-out of incremental natural gas takeaway capacity out of the Marcellus/Utica region has come in fits and starts, with new pipelines—as opposed to the reversal or expansion of existing pipes—proving to be the most troublesome. Energy Transfer Partners and Traverse Midstream Holdings’ long-planned 3.25-Bcf/d Rover Pipeline to southern Michigan is a case in point. The latest challenge for the $4.2 billion project is getting final federal approval in time to allow tree clearing along the pipeline’s 711-mile route to be completed before federally protected bats start roosting in early April. If that timeline’s not met, Rover’s planned completion later in 2017 may be delayed a full year, enabling Western Canadian gas producers to sell more gas to Ontario and the Upper Midwest. Today we assess what’s at stake for ETP, Traverse, and producer-shippers in the Marcellus/Utica and Western Canada.
There’s good reason to believe that the international LNG market has turned a corner, with demand and LNG prices on the rise and with a number of new LNG-import projects being planned. That would be good news for U.S. natural gas producers, who know that rising LNG exports will boost gas demand and support attractive gas prices. It also would help to validate the wisdom of building all that liquefaction/LNG export capacity now nearing completion. Today we look at recent developments in worldwide LNG demand and pricing and how they may signal the need for more LNG-producing capacity in the first half of the 2020s.
Each winter, New York spot prices for gasoline and diesel spike higher than spot prices in Chicago, opening a seasonal arbitrage opportunity for Midwest refineries and motor fuel marketers—if only they could move more product east from Petroleum Administration for Defense District (PADD) 2 to the East Coast’s PADD 1. Midstream companies have taken note, and have been adding eastbound refined product pipeline capacity in Ohio and Pennsylvania. So far the aim has been to move gasoline and diesel as far east as central Pennsylvania, but the longer-term goal seems to Philadelphia, which ironically is the center of East Coast refining. Today we look at the ongoing shift in market territories claimed and sought by gasoline and diesel refineries and marketers in PADDs 1 and 2.
The Western states continue to ramp up their renewable energy mandates—California and Oregon, for instance, plan to get at least 50% of their electricity from renewable sources, and Colorado has set a 30% requirement. Ironically, this renewable energy trend puts a spotlight on natural gas, whose at-the-ready supply will be needed to fuel the West’s increasing number of gas-fired power plants at a moment’s notice to offset the up-and-down output of solar facilities and wind farms. One way to help ensure natural gas availability is have gas storage capacity close at hand. Today we look at ongoing efforts to add tens of billions of cubic feet of natural gas storage in the Western U.S., primarily to help ensure the fueling of nearby gas-fired power plants that back up variable-output solar and wind.
Mexico’s consumption of motor fuels is rising, its production of gasoline and diesel continues to fall, and U.S. refineries and midstream companies are racing to fill the widening gap. The export volumes are impressive: deliveries of finished motor gasoline from the U.S. to Mexico averaged 328 Mb/d in the third quarter of 2016, up 41% from the same period last year, and exports of low-sulfur diesel were up 29% to 194 Mb/d. And there’s good reason to believe that U.S.-to-Mexico volumes will keep growing. Today we look at recent trends in gasoline and diesel production and consumption south of the border, and at ongoing efforts to enable more U.S.-sourced gasoline and diesel to reach key Mexican markets by rail and pipeline.
It’s been a tough few years for Canadian oil producers. As they ramped up production in the oil sands, Canadian E&Ps faced pipeline takeaway constraints that drove down the price of Western Canadian Select versus Gulf Coast crudes. The Keystone XL pipeline would have largely solved things, but when that project was killed by Canada’s U.S. friends and neighbors, oil sands producers had to settle for a series of smaller, more incremental projects that provided only a partial fix. The devastating Alberta fires of May 2016 reduced production and pretty much eliminated constraints for much of this year. But volumes have recovered, and if oil sands production is to continue growing, more pipelines and new customers will be needed. Today we consider Canada’s long-running effort to ensure there’s enough capacity to move its crude to market, two major projects that just won the backing of the Canadian government, and what may be next.
The frac spread—the difference between the value of a typical basket of NGLs and the price of natural gas, in $/MMBtu—has averaged a paltry $2.28 for the past two years, by far the longest period of depressed NGL values since the start of the Shale Revolution. That’s bad news for natural gas processing economics, which are most favorable when NGL prices are strong and natural gas prices are weak. But things are about to get a lot better. Today we consider the currently low frac spread, what it means for natural gas producers and processors, and why a big turnaround may be in the offing.
Every day, crude oil producers on Alaska’s North Slope re-inject nearly 7.8 Bcf of natural gas into their wells, enough gas to supply the entire U.S. West Coast—California, Oregon and Washington State. If only there were some way to monetize that gas supply, to move it to market. The problem is that there isn’t, at least in today’s gas/LNG market, which is characterized by ample supply and relatively low prices. This same market also favors infrastructure projects that are simple and low-cost; no one wants to make multibillion-dollar commitments when natural gas prices and margins are so low. Today we conclude our series on the tough times ahead for Alaska’s energy sector with a look at the state’s vast natural gas reserves and the challenges associated with tapping them.
Forecasting in U.S. energy markets characterized by hair-trigger price volatility, ever-improving well drilling and completion productivity, and the unraveling of old norms is a bit of a high-wire act. But just as big-tent tightrope walkers get better with practice, energy prognosticators can gain from experience––and from taking a look back at previous forecasts to see what they got right, what they may have missed, and what’s changed in the interim. Today we continue our review of a recent presentation at RBN’s School of Energy earlier this month on forecasting lessons learned.
The Shale Revolution changed everything about U.S energy markets, and in the process made forecasting the production and pricing of crude oil, natural gas and NGLs a heck of a lot harder. But we all learn from experience. In the early days of the Revolution, few could have predicted how quickly output would rise, how challenging it would be for pipeline takeaway capacity to keep up with production, or how successfully crude-by-rail would fill the gap – until that gap went away with the Revolution’s most recent phase. Comparing past forecasts to what actually happened is instructive though, and maybe––just maybe––today’s projections for the future are more informed than the forecasts of 2011 or 2013. In today’s blog we look at a recent presentation on forecasting lessons learned at RBN’s School of Energy earlier this month.
Intrastate natural gas pipelines in Texas reach far and wide, and can transport extraordinary volumes of gas. The problem is, the traditional supply/demand dynamics that spurred the development of all that pipe decades ago are being up-ended by burgeoning Marcellus/Utica production headed to the Gulf Coast and the demand-pull of gas to planned LNG export terminals along the Texas coast and to Mexico. Lone Star State pipelines that for years have flowed north and east to the Houston Ship Channel and beyond now must flow south and west. Today, we continue our review of efforts to rework and expand key elements of Texas’s intrastate gas pipeline network to meet growing export needs, this time with a look at plans by Enterprise Products Partners.