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.
Daily energy Posts
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.
The last couple of years have been a wild ride for the U.S. ethane market, but look out ahead. It’s going to get crazy. The onslaught of new, ethane-only crackers is upon us at the same time overseas exports are expected to ramp up. At first glance, it might appear there is enough ethane to meet all that demand, coming from molecules that today are being rejected — that is, sold as natural gas rather than liquid ethane. But the big question — will it be enough? Because not all that rejected ethane has access to pipeline capacity needed to get it to market, at least not right now. In today's blog, we begin a new series on rising ethane demand, how the new demand will be met, and what it all means for ethane prices.
For the first time in six years, pipeline flow data show that natural gas production from Louisiana’s Haynesville Shale is rising. Additionally, rig counts and producers’ plans suggest more growth is on the way. Is the play poised to create a whole new crop of Bayou Billionaires? Or is this a head fake that will only make us long for days of Haynesville past. Well, it depends. Because even though the Haynesville basin is looking up, it still faces some formidable challenges, from its geology to competition from other supply regions. Today, we continue our look at Haynesville’s prospects.
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.
For much of the past few years, natural gas at Northeast demand market hubs has been priced at deep discounts, particularly in the low-demand summer months, because of the flood of Marcellus Shale gas that couldn’t go anywhere else. But now, those markets could soon see some upward pressure as pipeline projects that will expand takeaway capacity from the region come online. One of those projects is Williams’s Transco Pipeline Dalton Expansion, which includes an expansion of Transco’s mainline as well as a new, “greenfield” lateral. The project has already commenced partial-path service to move as much as 448 MMcf/d south on the mainline from Transco’s Zone 6 in New Jersey to its Zone 4 segment in Mississippi. And just yesterday (Thursday, July 13), Transco submitted a request with the Federal Energy Regulatory Commission (FERC) to place the remaining portion — the new Dalton Lateral pipeline extension and related connections — into service less than three weeks from now (on August 1). Today, we provide an update on the project and potential market effects.
The weekly estimate of commercial crude oil inventories in the U.S. Department of Energy’s Weekly Petroleum Status Report — and the week-on-week change in those inventories — are among the most closely watched numbers in the oil sector. And for good reason. After all, the numbers help the market assess shifts in the supply/demand balance, a critical consideration in determining crude oil prices and signaling the need for more — or less — imports, exports, and of course production. In 2017, with a mandated drawdown in the Strategic Petroleum Reserve, it is now important to track weekly withdrawals from the SPR as well because of the effect they can have on commercial stocks. Today we discuss recent and planned SPR drawdowns and their effect on the supply/demand balance and crude oil prices.
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 Waha Hub in West Texas figures to play a prominent role in supplying natural gas to Mexico soon, as pipelines connecting the Permian Basin to the international border are now complete and supplying small volumes to Northwest Mexico. As additional pipelines and power plants come online south of the border over the next 12 months, a meaningful ramp-up in flows from Waha to Mexico is expected. Facilitating those flows will be a Waha-area header recently built by a consortium of Carso Energy, MasTec and Energy Transfer Partners for Mexico’s Comisión Federal de Electricidad (CFE). With 6 Bcf/d of capacity and multiple pipeline interconnects, the header stands to dramatically improve interconnectivity among gas pipelines at Waha, but it has largely stood in the shadows of Mexico’s pipeline buildout. Today we continue our series on the Waha Hub with a look at CFE’s Waha header and its expected role in handling Permian-sourced gas.
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.
Midstream giant Enterprise Products Partners (EPD) has attracted significant investor interest because of its simplified structure, 51 consecutive quarters of dividend growth and strong coverage — $2.7 billion in retained cash in the past three years. The company, with a market capitalization of $58 billion, has also quietly continued to build out its large integrated midstream network despite the plunge in commodity prices, investing almost $18 billion in organic growth projects and acquisitions in 2014-16. The end result is impressive: Enterprise is now connected to every major U.S. shale basin, every U.S. ethylene cracker and 90% of the refineries east of the Rocky Mountains. As a result, the company is well positioned to benefit from the recovery in oil and gas production, especially in the Permian Basin and Eagle Ford Shale; the surge in hydrocarbon exports; and the rapid growth of the U.S. petrochemical industry. Today we discuss highlights from the second part of our new Spotlight analysis of EPD, which focuses on the company’s Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and Petrochemical & Refined Products Services segments.
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.
Booming Permian natural gas production has increasingly stressed pipeline takeaway in recent months as volume rose to more than 6 billion cubic feet per day (Bcf/d) — up almost 1 Bcf/d from the year-ago level. The production surge has broadened price spreads not only between Waha and other regional hubs, but also within the Permian between Waha and its sister hub, the El Paso Pipeline-Permian price pool. Creative midstream solutions are aimed at relieving these constraints, both in the form of long-haul takeaway and intrabasin pipelines. Of the latter form, few projects have moved with the speed and size of WhiteWater Midstream’s Agua Blanca. Today we continue our series on the Waha Hub with a look at intrabasin Permian midstream gas flows and how Agua Blanca is expected to keep them moving.
New production expected online in December 2017 from the Suncor Fort Hills project in the oil sands region of northern Alberta could increase pipeline congestion from western Canada to the U.S. Gulf Coast market where the oil is in demand. That’s because existing capacity across the Canadian border is running close to full and the only possible capacity addition across before 2019 is Enbridge’s 300-Mb/d Alberta Clipper expansion at the border — assuming it gets a long-sought U.S. Presidential Permit later this year. As a result of this continuing near-term pipeline squeeze, producers are again turning to rail transport to bypass pipeline congestion and ensure their crude gets to market. On June 2 (2017), USD Group announced a new route option for Canadian producers following its purchase of a rail terminal in Stroud, OK, that is connected by pipeline to the Midwest crude trading and storage hub at Cushing, OK; USD will offer direct rail service from its Hardisty, AB, terminal to Cushing. Today we review the economics of this rail transport route for oil sands producers. (This blog is based on a recent note published by Morningstar Commodities and Energy Research.)