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.

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.

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.

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.

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.