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.
Daily energy Posts
As it builds out the nation’s oil and natural gas pipeline networks to keep pace with ever-changing needs, the midstream sector has faced a number of challenges, perhaps chief among them regulatory delays exacerbated by organized environmental opposition. An oft-repeated priority of the new administration has been to make it easier to advance the development of new energy infrastructure development. That raises a few questions. How much difference will this apparent change in attitude make? Should we expect a huge surge in new pipeline projects to be approved and move forward? Today we examine major projects that have faced drawn-out approval processes and evaluate the degree to which a new administration can grease the skids for new pipelines.
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.
The latest Drilling Productivity Report from the EIA, released yesterday (February 13, 2017), shows that while the combined rig count in the seven major U.S. shale plays rose about 25% in the fourth quarter of 2016 versus the previous quarter, and the number of wells drilled was up 29%, well completions were up a paltry 1%, leading to an increase in the inventory of drilled-but-uncompleted wells (DUCs). Completions accelerated a bit in January 2017, but DUCs still continued to rise. That certainly seems counterintuitive. With crude oil prices stable in the low $50’s over the past few months you might think that producers would be pulling DUCs out of inventory, and in fact there have been statements to that effect in several producer investor calls. This is not just an exercise in energy fundamentals numerology. If the DUC inventory is increasing, then production will not be ramping up as fast as the growing rig count would imply. But what if, as some early signs indicate, the historical relationships are out of whack and the DUC inventory isn’t growing but rather declining? In that case, forecast models could be understating the outlook for production growth, and the market could be in for a more rapid and steeper rebound in oil and gas production than many expect. In today’s blog, we delve into the DUC inventory data and its potential upside risk to production forecasts.
More than a dozen crude oil pipelines can deliver up to 3.4 million barrels/day (MMb/d) to the greater Houston area, with another 550 Mb/d of capacity planned, and as domestic production starts to grow again, a new round of projects is under way to build-out the region’s distribution pipelines, storage and marine-dock infrastructure. The developers of these Houston-area projects include a range of midstream players: from large, diversified midstreamers that own the long-distance pipelines flowing into the region to smaller players planning their first Houston projects. Today we conclude a two-part blog series on the latest round of projects and on the increasingly intense competition for barrels.
South Texas—and its primary trading hub, Agua Dulce—is emerging as the fulcrum for U.S. natural gas producers and growing demand markets on the Texas Gulf Coast and across the border in Mexico. Between the Freeport and Corpus Christi LNG export projects and cross-border pipeline projects to Mexico, nearly 4.0 Bcf/d of export capacity is being developed in South Texas over the next few years. Meanwhile, U.S. producers as far north as the Marcellus/Utica are jockeying to capture this new demand. Large investments are being made to expand and reverse traditional pipeline flows across the Texas-Louisiana border to get gas all the way down to South Texas and the Texas-Mexico border. But will enough capacity be available when the demand shows up? Today, we break down the natural gas supply/demand picture in South Texas and what it will take to balance the market there as exports ramp up.
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.
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.