U.S. LNG exports via Cheniere Energy’s Sabine Pass LNG export facility are poised to be a major demand driver of the domestic natural gas market in 2017. Pipeline deliveries to the terminal have more than tripled since mid-2016 and are set to climb further as more liquefaction capacity ramps up. With two liquefaction trains already operational, the Federal Energy Regulatory Commission last month approved Train 3 to begin operations and also green-lighted the start-up of Train 4 commissioning. Today, we provide an update of Sabine Pass’s export activity and its potential effect on U.S. gas demand this year.
Posts from Sheetal Nasta
The Florida natural gas market will soon have access to another supply source. In June 2017, the Sabal Trail Transmission natural gas pipeline project is expected to begin service, bringing the market one step closer to connecting Marcellus/Utica natural gas to demand markets on the increasingly gas-thirsty Florida peninsula. The project will increase gas supply options for growing power generation demand in the Sunshine State while effectively also increasing gas-on-gas competition between producers in the Northeast, Gulf Coast and Midcontinent. Today we provide an update on Sabal Trail and its related projects.
After spending the past few years on the backburner with declining production volumes, the Haynesville Shale natural gas play, which straddles the Northeast Texas-Louisiana border, is back in the headlines. Rig counts in the region have doubled in the Haynesville in the past six months or so. Exco Resources—which has four rigs operating there currently—last week said it is divesting its Eagle Ford assets in favor of boosting drilling investment in the Haynesville. At the same time, there’s a new crop of operators in the play dedicated specifically to drilling in the Haynesville. While total basin production volumes have yet to take off, all signs point to a Haynesville resurrection of sorts. But there are also early clues that much has changed since the first go-round and the drilling profile of today’s Haynesville is likely to look much different than it did nearly 10 years ago. Today we begin a look at RBN’s latest analysis of production economics in the Haynesville Shale.
Energy Transfer’s latest Texas-to-Mexico natural gas pipeline project—the 1.4-Bcf/d Trans-Pecos Pipeline—began service a little over a week ago (on March 31, 2017). It’s the third Tejas-to-Méjico gas transportation project to come online in the past six months, following the expansion of ONEOK’s Roadrunner Gas Transmission pipeline in October 2016 and the in-service of Energy Transfer’s Comanche Trail Pipeline in January 2017. The three projects have added a total of nearly 3.0 Bcf/d to pipeline export capacity since last October, all originating in the Permian Basin at the Waha gas trading hub in West Texas. A game-changer, right? Well, the reality is not so simple. These expansions on the U.S. side are largely reliant on takeaway capacity on the Mexico side of the border as well as the growth of power demand downstream to support flows, not all of which is coinciding with capacity additions on the U.S. side. Today we look at the latest export pipeline capacity additions and prospects for near-term export demand growth along the Texas-Mexico border.
At this time last year, the U.S. natural gas market was exiting an extremely bearish winter, the gas storage inventory was nearly 500 Bcf higher, and prompt month prices for the CME/NYMEX Henry Hub natural gas futures contract were more than $1.00/MMBtu lower. The question on our minds then was how far would production have to decline or how much demand was likely to show up to prevent storage capacity constraints by fall. In either case, the overarching sentiment was that prices would have to remain relatively low to balance the market. Now we’re exiting an almost equally mild winter, but a combination of lower production and higher exports has drawn down storage to well below year-ago levels, and the question occupying the market is more along the lines of, just how bullish could the market get this year? Today, we wrap up our look at injection season storage scenarios for the next seven months.
After exceptionally mild weather nearly derailed the U.S. natural gas market earlier this year, the gas supply/demand balance is set to end the 2016-17 withdrawal season relatively bullish compared to last year. Storage is finishing the season more than 400 Bcf lower than last year, albeit still 260 Bcf/d above the 5-year average. In addition, gas exports are continuing to ratchet higher. The April 2017 CME/NYMEX Henry Hub natural gas futures contract expired Wednesday (March 29) at $3.175/MMBtu, nearly $1.30 (67%) higher than the April 2016 contract settlement of $1.90/MMBtu and also about 55 cents higher than the March 2017 contract settlement. Yet, with the storage inventory still higher than the 5-year average and production growth on the horizon, the market remains susceptible to downside risk if incremental demand doesn’t show up. In today’s blog, we look at potential supply/demand scenarios for injection season.
Cheniere Energy last Friday announced it has signed precedent agreements (firm capacity deals) with foundation shippers for its 1.4-Bcf/d Midship Pipeline project, which is targeted for an early 2019 in-service date. The announcement marks the latest milestone for midstream companies looking to move natural gas production from the SCOOP/STACK shale plays in central Oklahoma to growing demand markets in the Southeast and along the Texas Gulf Coast. Production from SCOOP and STACK grew by 1.0 Bcf/d, or 60%, in the past three years to 2.7 Bcf/d in 2016 and is expected to grow by another 1.5 Bcf/d by 2021. Besides Midship, there are other projects vying to move SCOOP/STACK gas to market. But how much capacity is really needed and by when? Today we look at the Midship project and its role in alleviating potential takeaway constraints.
South Texas is emerging as the newest premium destination for natural gas supply in the U.S. Demand in the area is expected to grow much faster than local production, creating a supply shortage in the region by early 2018. New pipeline capacity will be needed to move incremental supply into South Texas. There are several projects planned to facilitate southbound capacity on pipelines running along the Gulf Coast Industrial Corridor. Today we examine the planned pipeline capacity and whether it will be enough to serve the coming demand.
The oil- and condensate-focused SCOOP and STACK shale plays in Central Oklahoma have been garnering the industry’s attention for their attractive producer economics, which are second only to the Permian among the crude oil shale plays. Rig additions in Oklahoma over the past several months are clearly targeting this 11-county area of the Anadarko Basin, and the RBN Production Economics Model projects production from the region will grow by 1.5 Bcf/d over the next five years. The increased drilling activity and expected production growth has piqued the interest of midstream companies looking to invest in infrastructure in the area. Given the increased output, is more takeaway capacity needed, and if so by when? Today we continue our look at the potential for takeaway constraints out of the SCOOP and STACK.
U.S. natural gas exports drove a significant portion of overall gas demand growth in 2016 and are expected to continue being the primary demand driver over the next several years. Much of this export demand will be emerging along the Texas-Mexico border and at planned LNG export terminals along the southern Texas Gulf Coast. But production in the South Texas region is not expected to grow nearly as quickly or robustly as demand, setting the stage for supply constraints and premium pricing in the South Texas market and making the area a target destination for producers and pipeline companies. For example, on Wednesday, Enterprise announced the possibility of a new pipeline from Orla, TX, in the Permian Basin to Agua Dulce in South Texas. So how will all of this play out? Today, we continue our series analyzing the gas supply and demand balance in South Texas, this time with a look at the demand side and the resulting market balance.
Natural gas production out of Oklahoma’s SCOOP and STACK plays has been resilient in the face of lower oil and gas prices and is expected to grow by about 1.5 Bcf/d over the next five years. But with the Marcellus/Utica increasingly competing for both pipeline capacity and demand markets outside the Northeast region, the question is where can and will the new SCOOP/STACK supply go? That will be dictated in large part by where demand is growing—primarily along the Gulf Coast—and where the price differentials are attractive. But flows also can be hindered or facilitated by another, preeminent factor: pipeline takeaway capacity. Today we explore the potential for takeaway constraints out of the SCOOP and STACK.
There is a premium natural gas market developing in South Texas, where exports to Mexico could rise by more than 2.0 Bcf/d over the next four years and gas liquefaction and LNG export facilities are expected to add another 1.8 Bcf/d of demand to the market in that time. While gas production from the nearby Eagle Ford Shale is showing signs of at least a partial comeback and will help meet some of this new demand, the South Texas market may be heading toward being short supply in the next few years, resulting in higher prices there relative to surrounding markets. That would make the South Texas market an attractive destination for supply as far north as the Marcellus and Utica shales. In fact, there is a slew of proposed southbound pipeline projects extending deep into Texas along the Texas Gulf Coast for shippers to get their gas there. But how much incremental supply will be needed to balance the market? Today we begin a series analyzing the gas supply and demand balance in South Texas, starting with prospects for production growth out of the Eagle Ford Shale.
The March 2017 CME/NYMEX Henry Hub natural gas futures contract has shed nearly 60 cents/MMBtu (17%) since February 1, 2017, and the rest of the 2017 curve has been slashed by an average 40 cents (12%) in that time. On February 1, prices for all 10 remaining 2017 futures contracts (from March to December 2017) carried $3 handles. Now, all but two contracts are below $3. Weather has been the primary driver of this shift. February 2017 is set to rank as the warmest February since 1970, after January 2017 also came in as one of the warmest in 40 years. Weather forecasts are also showing the warmth extending into March. These developments are signaling a more bearish 2017 than expected. Today, we continue our supply and demand update with a look at the 2017-to-date balance.
After ending 2016 on a bullish note, the U.S. natural gas market has been hammered so far in 2017 by relentlessly mild weather—January 2017 ranked as the fifth warmest in 40 years. The prompt CME/NYMEX Henry Hub futures contract, which had climbed to nearly $4.00/MMBtu by late December 2016, has come off more than $1.00 since then to settle at $2.834/MMBtu as of last Friday (February 17, 2017). With every balmy winter day that passes, the chances of sustained $3-$4 natural gas prices seem to be fading away. Nevertheless, there are still some bulls out there hanging on in hopes of a rebound. Prices are still well above year-ago levels and the underlying supply/demand balance continues to carry the implied potential for tightening if given even normal weather. In today’s blog, we provide an update of the gas supply/demand balance, starting with a recap of how we got here.
The latest Drilling Productivity Report from the EIA, released yesterday (February 13, 2017), shows that while the combined rig count in the seven major U.S. shale plays rose about 25% in the fourth quarter of 2016 versus the previous quarter, and the number of wells drilled was up 29%, well completions were up a paltry 1%, leading to an increase in the inventory of drilled-but-uncompleted wells (DUCs). Completions accelerated a bit in January 2017, but DUCs still continued to rise. That certainly seems counterintuitive. With crude oil prices stable in the low $50’s over the past few months you might think that producers would be pulling DUCs out of inventory, and in fact there have been statements to that effect in several producer investor calls. This is not just an exercise in energy fundamentals numerology. If the DUC inventory is increasing, then production will not be ramping up as fast as the growing rig count would imply. But what if, as some early signs indicate, the historical relationships are out of whack and the DUC inventory isn’t growing but rather declining? In that case, forecast models could be understating the outlook for production growth, and the market could be in for a more rapid and steeper rebound in oil and gas production than many expect. In today’s blog, we delve into the DUC inventory data and its potential upside risk to production forecasts.