Production of natural gas liquids in the Permian is growing so quickly that within a year or two some parts of the super-hot play may experience NGL takeaway constraints. That is good news for the owners of the eight existing NGL pipelines out of the Permian, which are likely to see flows on their pipes increase as NGL production rises — assuming, that is, that they have capacity to spare and that they are connected to natural gas processing plants within the faster-growing parts of the region. Today we continue our blog series on Permian NGL production, processing and pipelines with a look at ONEOK’s West Texas LPG Pipeline and the Chevron Phillips Chemical EZ Pipeline.
Posts from Housley Carr
The stars may finally be aligning for two related crude oil infrastructure projects that, if undertaken, would provide an important new pathway to overseas markets for Bakken, western Canadian and other North American crude. The first would involve reversing the Capline Pipeline, which was built to transport crude north from the U.S. Gulf Coast to Midwest refiners; the second would make modest physical changes to the Louisiana Offshore Oil Port — better known as LOOP — to allow the crude import facility off the Bayou State coast to load crude onto ships, including Very Large Crude Carriers (VLCCs). Today we look at the new infrastructure and market forces that may finally spur Capline’s reversal and lead imports-focused LOOP to enable exports.
Nearly two-thirds of the effective NGL pipeline takeaway capacity out of the Permian is controlled by Energy Transfer Partners and DCP Midstream. But there are several other NGL pipelines used to flow Permian NGLs to faraway storage facilities and fractionators — assuming, that is, that their natural gas processing plants are connected to the pipe alternatives in question. Today we continue our blog series on the NGL side of the Permian with a look at Enterprise Products Partners’ Chaparral and Seminole pipelines and Enterprise’s and BP’s Rio Grande Pipeline, including the volumes of NGLs that have been flowing through them.
The year-ago completion of Energy Transfer Partners’ Lone Star Express NGL pipeline from West Texas to the Mont Belvieu storage and fractionation hub near Houston was a big deal. The new, 533-mile pipe increased effective NGL takeaway capacity out of the Permian by more than 25% and gave Energy Transfer a larger conduit for moving NGL produced at its Permian natural gas processing plants directly to the company’s still-growing complex of fractionators in Mont Belvieu. Energy Transfer also owns another big NGL pipeline out of the Permian: the Lone Star West Texas Gateway. Today we continue our blog series on the NGL side of the Permian with a look at what is currently the biggest fish in the play’s NGL pond.
The utilization of NGL takeaway pipelines out of the fast-growing Permian is determined to a significant degree by the natural gas processing plants that the pipes are connected to. Midstream companies prescient — or lucky — enough to own NGL pipelines that extend out of the hottest, most productive sub-regions within the Permian’s Midland and Delaware basins are benefiting not only from higher NGL volumes now, but the likelihood of even fuller pipes as Permian production continues to ramp up. Today we continue our blog series on the NGL side of the Permian phenomenon with a look at existing gas processing plants in the play and their connections to NGL pipelines that move y-grade to storage and fractionators.
A big question mark hanging over the Permian like a dark cloud is whether there will be sufficient pipeline takeaway capacity to deal with continued production growth in the U.S.’s hottest shale play. Mostly, takeaway-adequacy questions are asked about either crude oil or natural gas, but ensuring sufficient NGL pipeline capacity out of the Permian may ultimately be the biggest challenge of all. Why? Because just about everything involving NGLs seems to be more complicated — how they are produced, transported, stored and even priced. Today we begin a series on Permian natural gas processing, natural gas liquids production growth and existing plus planned NGL pipelines out of West Texas and southeastern New Mexico.
The rig count in the Niobrara Shale’s Denver-Julesburg (DJ) Basin has doubled in the past year, and crude oil production has been rebounding modestly in recent months. Most of the activity in the play is concentrated in super-hot Weld County, CO, where 23 of the DJ Basin’s 29 active rigs are set up. But with crude prices below $50/barrel, will the DJ make a real comeback, or will production sag again, just like it did after the big price declines of 2014-15? And what about Niobrara-related midstream infrastructure? Even some of the more optimistic forecasts leave the region with far more pipeline takeaway capacity than it needs. Today we consider recent developments in the Rocky Mountain region’s most important shale play and what they mean for exploration and production companies and midstreamers.
MPLX is wrapping up a three-part, $500 million plan to facilitate the pipeline transport of large volumes of field condensate and natural gasoline from the Marcellus and Utica plays to Midwest refineries, western Canadian heavy-crude shippers and other end users. But “wrapping up” may be the wrong phrase. In fact, MPLX sees its Cornerstone Pipeline, Utica Build-Out Projects and other elements of the company’s Midwest pipeline push as part of a larger and continuing effort to deal with remaining inefficiencies in the delivery of Marcellus/Utica liquids to market. Today we review what has been accomplished so far, and what expansions and enhancements to MPLX’s pipeline plan may be in the offing.
Permian natural gas production is up nearly 40% over the past three years to 6.3 billion cubic feet/day (Bcf/d), and production could almost double to 12 Bcf/d by 2022. While there is 10.8 Bcf/d of existing gas takeaway capacity out of the Permian — suggesting that takeaway constraints are not imminent — much of the capacity to Mexico is not currently usable because of delays in related power-generation and pipeline projects south of the border. There also are limits to how much of the gas pipeline capacity from the Permian to California can be used for Permian takeaway, particularly during the off-season, when California can serve much of its incremental power load from hydro, solar and wind. The Midcontinent (Midcon) and Upper Midwest can only take so much Permian natural gas too; they’re taking gas from almost every direction. Put simply, takeaway constraints out of the Permian may be much closer than they appear. Today we consider existing natural gas takeaway capacity out of the Permian, how it compares with current and projected gas production in the region, and the potential for — and timing of — constraints that could reduce the prices that Permian producers receive for their gas.
It may take a number of years to pan out, but Mexico is taking steps to accelerate the development of its natural gas-rich Burgos Shale region, which lies just across the Rio Grande from South Texas’s newly resurgent Eagle Ford play. Today (July 12, 2017), Mexico’s Secretaría de Energía (SENER) is expected to name the winners of a competitive bidding process for the rights to drill for natural gas within 1,500 square miles in the states of Nuevo Leon and Tamaulipas. If the effort to juice Burgos drilling activity and production proves successful, it could affect how much natural gas Mexico needs to import from the U.S. Today we discuss the prospects for reversing gas production declines south of the border and the challenges that exploration and production companies (E&Ps) face in Mexico’s most promising shale play.
Production of associated natural gas in the Permian’s Midland and Delaware basins is forecasted to continue rising through the early 2020s, challenging existing pipeline takeaway capacity out of the region. There also are limits to how much gas can flow northeast into the Midcontinent and the Upper Midwest — after all, those regions have access to gas from other areas too, including the Rockies, western Canada, the Marcellus/Utica and the Midcon itself. The same holds true for Texas’s Gulf Coast, which has emerged as another battleground for gas producers. Today we continue our series on the ability of existing pipes out of the Permian to move natural gas to market and the enhancements that will be needed to allow Permian production to keep growing.
The international spot price for liquefied natural gas (LNG) has been steady-as-she-goes the past few months, within a few dimes of $5.50/MMBtu, but that stability belies the upheavals the LNG industry continues to experience. The old paradigm of long-term contracts and milk-run deliveries from supplier to buyer is breaking down. New Australian and U.S. liquefaction capacity is coming online fast and furious, exacerbating the global LNG supply glut, and Qatar — the world’s largest LNG supplier, just announced plans to increase its output by 30%. With LNG readily available and priced to sell, new LNG buyers are entering the fray, developing natural gas-fired power plants that will be fueled by imported LNG. What does all this mean for the next wave of U.S. liquefaction projects and for natural gas producers in the Marcellus/Utica and the Permian? Today we continue our look at the topsy-turvy LNG sector.
The pace of production growth in the Permian’s Midland and Delaware basins will be influenced by many factors, including the degree to which the market price for crude oil exceeds the play’s breakeven prices and the ability of midstream companies to add incremental pipeline takeaway capacity as that capacity is needed. While the pursuit of crude oil is driving drilling and production activity in the Permian, rapid growth in crude output is accompanied by large volumes of associated gas and NGLs that also must be dealt with. Fortunately, the Permian has been a major production area for decades — a lot of gas and NGL pipeline infrastructure is already in place. But it won’t be enough. Today we begin a blog series on the existing networks’ ability to move natural gas to market and the enhancements that will be needed to keep the Permian’s growth on track.
Plans are afoot to double and maybe triple the liquefied petroleum gas (LPG) export capacity of the Pacific Northwest — British Columbia, Washington State and Oregon — giving the region an enhanced role in what has been a booming business. Volumes being shipped to Asia out of the Ferndale marine terminal in northwestern Washington State are at near-record levels, and AltaGas and Royal Vopak are building a 40-Mb/d (and expandable) export facility in northwestern BC that is planned to come online in early 2019. Further, Pembina may be only months away from committing to the construction of a 20-Mb/d LPG marine terminal, also in BC. Today we continue our series on the expanding role of Western Canada in LPG exports with a look at plans for new propane/butane marine-dock capacity in BC.
Drilling, well completions and multibillion-dollar investments in the Permian are being driven by the region’s potential for producing vast quantities of crude oil. But the Permian juggernaut isn’t only about crude — far from it. Over most of the past 12 months, the fastest-growing energy commodity in the Permian wasn’t crude oil, it was natural gas. And consider this: The U.S. play with the lowest breakeven prices for natural gas is not the Marcellus/Utica. It’s the Permian, where many of the most prolific areas have negative natural gas breakeven prices. And perhaps most important, constrained gas takeaway capacity poses a bigger threat to Permian crude production growth than constrained crude takeaway capacity, because if the gas produced in the play can’t be transported to market, crude production may need to be curtailed. Today we discuss highlights from RBN’s new Drill Down Report, which focuses on the all-important gas side of the U.S.’s hottest hydrocarbon production region.