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.
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.
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.
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.
After posting huge pretax operating losses in 2015-16, the nine U.S. natural gas-focused exploration and production companies (E&Ps) we’ve been tracking returned to profitability in the first quarter of 2017. This reversal of fortunes in peer group performance was driven mostly due to higher natural gas prices, which ended a massive flow of red ink that had principally resulted from big reserve write-downs. Now, with higher profits and cash flows, these producers are ramping up their 2017 capital budgets and planning for long-term production growth. Today we continue our series on the financial performance of 43 U.S. E&Ps, this time zeroing in on companies whose hydrocarbon reserves are mostly natural gas.
Permian natural gas production has climbed 1.75 Bcf/d, or nearly 40%, in the past three years to more than 6.3 Bcf/d in 2017 to date, and it’s poised to grow to nearly 12 Bcf/d over the next five years. Note that’s a “dry” or “residue” gas number; gross gas production is a couple of Bcf/d higher. As Permian production growth occurs, pipeline takeaway capacity from the primary trading hub in the area — the Waha Hub — will become increasingly constrained, a trend that will drive pricing and flow dynamics into the early 2020s. How full are the takeaway pipelines now and how quickly will constraints emerge? Today we continue our series on the Waha Hub with a look at current takeaway capacity and flows from the hub.
Rising volumes of associated natural gas production from accelerating oil-directed drilling in the Permian, along with growing demand downstream in Mexico and along the Texas Gulf Coast, are placing renewed importance on a key West Texas trading hub and pricing point — Waha. Permian gas production climbed almost 900 million cubic feet/day (MMcf/d) during 2016 to nearly 6.0 billion cubic feet (Bcf/d), and is up another 400 MMcf/d since then. Moreover, the pace of growth shows no signs of slowing. Much of this incremental supply will rely on the pipeline interconnects and takeaway capacity available at the Waha trading hub to get to desirable markets. The questions that arise, then, are, will the capacity at Waha be sufficient and at what point will more be needed? Today we begin a series diving into the infrastructure, gas flows and capacity at Waha.
If you missed the Golden State Warriors’ NBA Championship win last week, or an unbelievable putt at the U.S. Open this weekend you can always see it on ESPN’s SportsCenter. But what if you missed the most recent RBN School of Energy? Well, you’re in luck — we’re now offering 11 hours of video from SOE, which unlike other natural gas, crude oil or NGL conferences covers all three markets with hands-on course work. In each of the seven streaming-video modules, we drill down on an important aspect of the markets, explain how it works and provide spreadsheet models accompanied with instructional videos. Fair warning: Today’s blog is an unabashed advertorial.