Crude oil production in the Permian Basin is now approaching 4 MMb/d, and with more than 2 MMb/d of new pipeline takeaway capacity out of the resource-rich play set to come online over the next 12 months, there soon will be plenty of room for more production growth. To efficiently transport crude to takeaway pipes, however, producers and shippers need ever-growing networks of gathering systems in the Permian’s sweet spots where much of the drilling and completion activity is occurring. Ideally, these systems offer their users a high degree of optionality — that is, interconnections with multiple takeaway pipelines to different markets — so they can capture the best prices for their oil. Today, we continue our review of major gathering networks in the Permian with a look at Reliance Gathering’s nearly 250-mile system in the Midland, TX, area.
Only a few months after major crude oil takeaway constraints out of the Permian Basin caused price spreads to widen, the pipeline network serving the U.S.’s most prolific shale play may be on the brink of becoming overbuilt. We’ve already seen a number of new expansions and pipeline conversions completed in the past six months, and construction is underway on another 2 MMb/d of new pipeline capacity scheduled to come online between now and the first quarter of 2020. Beyond that, a few remaining projects have been proposed but have not yet reached final investment decisions. No midstream group wants to build a pipeline that will be half full, and no producer wants to make a 10-year commitment to a pipeline if there are going to be plenty of other options available. So who blinks first? In today’s blog, we review the Permian pipeline projects that are still on the fence and examine what factors will determine whether they end up being a “go” or a “no.”
The rapid development of the Permian’s vast hydrocarbon resources that we expect will continue through the 2020s and beyond can’t happen if there’s insufficient gathering-pipeline infrastructure in place to transport crude from well sites to takeaway pipelines. Similarly, the favorable pricing that Permian producers hope to receive for their crude oil is possible only if their gathering systems are interconnected to two or more long-haul, big-bore pipelines that offer them some serious destination optionality. The need for new gathering pipes with multiple links to Gulf Coast- and Cushing-bound takeaway pipes is the driving force behind the Beta Crude Connector, a planned 100-mile-plus pipeline network in the heart of the Permian’s Midland Basin that was unveiled on Monday (April 15) by a joint venture of Concho Resources and gathering specialist Frontier Energy Services. Today, we kick off a new blog series on crude-gathering projects in the Permian with a look at the Concho/Frontier plan.
It’s said that everything is bigger and better in Texas, and when it comes to the magnitude of negative natural gas prices, the Lone Star State recently captured the crown by a wide margin. By now, you’ve probably heard that Permian spot gas prices plumbed new depths in the past couple of weeks, falling as low as $9/MMBtu below zero in intraday trading and easily setting the record for the “biggest” negative absolute price ever recorded in U.S. gas markets. Certainly, that was bad news for many of the Permian producers selling gas into the day-ahead market. But every market has its losers and winners, and negative prices were likely “better” — dare we say much better — for those buying gas in the Permian. Today, we look at some of the players that are benefitting from negative Permian natural gas prices.
The winter 2018-19 natural gas market was one of the most chaotic in recent memory, with the NYMEX Henry Hub futures contract last fall rocketing up to nearly $5/MMBtu in a matter of weeks, only to collapse in late 2018/early 2019 to an average $2.60 in January. The physical gas market also swung to extremes in recent months, setting both the highest ($200/MMBtu at the Sumas, WA, hub) and lowest (negative $9.00/MMBtu at the Waha hub) trades ever recorded in the U.S. These anomalies occurred amid steep supply growth from the Marcellus/Utica and Permian producing regions and rapidly advancing demand, particularly from burgeoning LNG exports along the Gulf Coast, while infrastructure scrambled to keep pace to bridge the two. And there’s more of that volatility ahead. Close to 5 Bcf/d more LNG export capacity is being added this year alone, and Lower-48 gas production is poised to continue growing. Today, we lay out our view of the recent volatility and the biggest factors shaping the gas market over the next five years, based on Rusty Braziel’s Backstage Pass Fundamental Webcast last week.
Crude differentials in the Permian are getting squeezed. The spread between Midland and WTI at Cushing widened out to near $18/bbl at one point in 2018, when pipeline capacity was scarce. But that same spread averaged a discount of only $0.25/bbl in March 2019. Differentials between Midland and the more desired sales destination at the Gulf Coast are also in a vise. What gives? Production in the Permian continues to climb, but the rapid pace of growth we saw in 2018 has slowed down a bit lately, with fewer rigs in service and fewer new wells being brought on each month. More importantly, we’ve seen several new pipeline expansions and pipeline conversions come online in bits and bursts — in some cases, ahead of schedule — and this new chunk of pipeline space has compressed Midland pricing. In today’s blog, we begin a series on Permian crude takeaway capacity and differentials, with a look at the handful of new projects that have come online in the past few months and what has happened to Permian prices as a result.
Permian natural gas prices are having a rough spring. After a volatile winter that saw two periods of negative-priced trades followed by a period of relatively strong prices, values at the Permian’s major trading hubs hit the skids earlier this week just as Spring Break set in for most in the Lone Star state. Once again, pipeline maintenance and burgeoning production appear to be the main culprits, but this upheaval feels different, in our view. Clearly, the price crash has reached a new level of drama, with day-ahead spot prices at West Texas’s Waha hub now settling below zero — some days by more than $0.50/MMBtu. Gas production has raced higher too, now within striking distance of 10 Bcf/d, on the coattails of continued oil pipeline capacity expansions, but new gas pipeline takeaway capacity is an estimated six months away. What becomes of Permian gas prices in the meantime, and how much worse could already-negative prices get? Today, we discuss the drivers behind the latest price deterioration and assess what’s ahead for the Permian natural gas markets.
There’s never a dull moment in the ethane market. Four new steam crackers and an expansion at an existing plant are slated to begin operating along the Gulf Coast in 2019, and a recently restarted Louisiana cracker will continue to ramp up to full capacity — together adding about 250 Mb/d of ethane demand by year’s end. You’d think there would be plenty of ethane out there for them. After all, U.S. NGL production has been on the rise, driven in part by new Permian gas processing plants and new NGL pipeline capacity to the coast. But fractionation constraints at the Mont Belvieu hub are likely to linger through 2019, raising questions about how much ethane will actually be produced and how much will need to be rejected into pipeline gas. Today, we consider the challenges facing the ethane market this year as demand increases and fracs run flat out to keep pace.
The U.S. frac sand market has been turned on its head. Over the past three years, demand for the sand used in hydraulic fracturing has more than doubled, dozens of new “local” sand mines have been popping up within the Permian and other fast-growing plays, and frac sand prices have fallen sharply from their 2017 highs. The big changes don’t end there. Exploration and production companies (E&Ps), who traditionally left sand procurement to the pressure pumping companies that complete their wells, are taking a more hands-on approach. And everyone is super-focused on optimizing their “last-mile” frac sand logistics — the delivery of sand by truck, plus unloading and storage of sand at the well site — with an eye toward minimizing completion costs and maximizing productivity. Today, we begin a blog series on the major upheavals rocking the frac sand world in 2019.
The Mexican market is critically important to Permian producers. Rising gas demand south of the border — along with expected gains in LNG exports from new liquefaction/export facilities along the Gulf Coast — are key to their plans to significantly increase production of crude oil, which brings with it large volumes of associated gas. All that gas needs a market, and nearby Mexico is a natural. For a number of years now, Mexico’s Comisión Federal de Electricidad has been working to implement a plan to add dozens of new gas-fired power plants and to support the development of new gas pipelines to transport gas to them from the U.S. The new pipelines have been coming online at a slower-than-planned pace. But what pipeline capacity has been added across the border from West Texas is already changing Mexico’s gas market. The El Encino Hub in Northwest Mexico is one such area where there are signs of a shifting supply-demand balance. Today, we continue a blog series on key gas pipeline developments down Mexico way and the implications for gas flows, this time delving into the dynamics at the El Encino Hub.
The forward curve for natural gas supports 2019 production growth that is likely to far outpace expected gains in gas demand. This impending supply/demand imbalance suggests that gas prices will be pressured lower. Lower gas prices will boost demand, but there are real limits to how much demand can rise in the short term. What will really be needed to balance the market is for producers in at least a few plays — the Marcellus and Utica among them — to rethink and rework their 2019 production plans. Which raises the questions, how much will production growth need to be cut, and where will the bulk of the pruning occur? Today, we continue our review of key themes and findings in East Daley Capital’s newly updated “Dirty Little Secrets” report on the midstream sector.
In the past month, two integrated majors with strong footprints in the Permian Basin announced plans to increase their refining capacity along the Texas Gulf Coast. During the last week of January 2019, ExxonMobil announced a final investment decision to expand its Beaumont, TX, facility’s capacity by 250 Mb/d, making it the largest U.S. refinery, and then confirmed an investment with Plains All American and Lotus Midstream to build a 1-MMb/d pipeline to ship crude to its Beaumont and Baytown, TX, refineries. In the same week, Chevron announced its purchase of the 110-Mb/d Pasadena, TX, Houston Ship Channel refinery from Brazil’s national oil company, Petrobras. Both Exxon and Chevron boasted record Permian production in their fourth quarter 2018 earnings calls. Today, we review Chevron’s purchase and Exxon’s expansion in light of Permian production growth and the changing Gulf Coast refining market.
The U.S. natural gas market last week was again reminded of the hair-trigger conditions that Permian producers and marketers are operating under — with gas production pushing against available takeaway capacity, all it takes is an otherwise minor/routine maintenance event on even one West Texas takeaway pipeline to send regional gas prices spiraling into negative territory. Waha Hub gas prices last week collapsed to their lowest level ever, with intraday trades even going negative — meaning some had to pay the market to take their gas. This wasn’t the first time that’s happened in the Permian — a similar event occurred in late November 2018 — but it was the worst to date and signals a heightened supply glut in the region, at least until the first new takeaway pipeline comes online in the fourth quarter of this year. Today, we explain the recent price weakness in West Texas and implications for Permian basis in 2019.
The dam has broken on the “second wave” of U.S. LNG export projects. ExxonMobil and Qatar Petroleum last week announced a final investment decision on their joint venture liquefaction and export project — called Golden Pass Products — at the brownfield site of the Golden Pass LNG terminal on the Texas side of the Sabine-Neches Waterway. That’s a skipping stone’s throw from Cheniere Energy’s Sabine Pass LNG and Sempra Energy’s Cameron LNG terminals on the Louisiana side of the Gulf of Mexico outlet, as well as a number of other second-wave contenders. With construction slated to begin late next month, the Golden Pass project expects to become operational and begin taking feedgas by 2024. Today, we provide an update on Golden Pass, its potential feedgas needs and how it will be supplied.
While Permian natural gas pipeline announcements came fast and furious last year, it had been relatively quiet on that front the past few weeks. Leave it to the folks at WhiteWater Midstream to break the lull, which is exactly what they did with the recent announcement of a binding open season for a new interstate pipeline in the heart of the Delaware Basin. Named Steady Eddy, the pipeline would originate in an underserved corner of the Permian and provide access to the Waha Hub, where a number of planned greenfield pipelines leaving the Permian will begin. Today, we look at the details of WhiteWater’s proposed Steady Eddy pipeline project.