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.
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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.
South Texas—and its primary trading hub, Agua Dulce—is emerging as the fulcrum for U.S. natural gas producers and growing demand markets on the Texas Gulf Coast and across the border in Mexico. Between the Freeport and Corpus Christi LNG export projects and cross-border pipeline projects to Mexico, nearly 4.0 Bcf/d of export capacity is being developed in South Texas over the next few years. Meanwhile, U.S. producers as far north as the Marcellus/Utica are jockeying to capture this new demand. Large investments are being made to expand and reverse traditional pipeline flows across the Texas-Louisiana border to get gas all the way down to South Texas and the Texas-Mexico border. But will enough capacity be available when the demand shows up? Today, we break down the natural gas supply/demand picture in South Texas and what it will take to balance the market there as exports ramp up.
Earlier this month, Tallgrass Energy’s Rockies Express Pipeline (REX) achieved full in-service of its 800-MMcf/d Zone 3 Capacity Enhancement Project, boosting the line’s east-to-west takeaway capacity out of Ohio to 2.6 Bcf/d, up 45% from 1.8 Bcf/d previously. Flows since then provide early indications of how Marcellus/Utica producers and downstream markets are responding to this added ability to move gas west. In today’s blog, we continue our look at how the expansion has impacted flows, this time with a focus on the delivery side.
Tallgrass Energy’s Rockies Express Pipeline earlier this month (on January 6, 2017) brought into service the last 350 MMcf/d of its 800-MMcf/d Zone 3 Capacity Enhancement Project, boosting the line’s east-to-west takeaway capacity out of Ohio to 2.6 Bcf/d, up 45% from 1.8 Bcf/d previously. The new, fully-subscribed capacity, designed to serve Marcellus/Utica producers, filled up almost instantaneously. But unlike previous capacity additions, Northeast production did not increase. Instead the gas came from other pipelines. This development provides an early indication of what the new capacity will mean for producers, flows and prices. In today’s blog, we delve into pipeline flow data to understand the early impacts of the new takeaway capacity.
Natural gas production from the oil- and condensate-focused SCOOP/STACK combo play in Oklahoma—one of the most productive plays in the U.S. currently—grew through 2016, even as other producing areas in the state, and in the Midcontinent as a whole, declined. As one of just a handful of locations that returning rigs are targeting, the SCOOP/STACK has the potential to single-handedly offset production declines in other parts of the U.S. Midcontinent and make Oklahoma a natural gas growth state again. Moreover, the RBN production economics model shows the natural gas output from the SCOOP/STACK has the numbers and the proximity to be directly competitive with gas supply from the Marcellus/Utica. Today, we continue our SCOOP/STACK series, with a look at the production economics driving interest in this play.
Northeast producers are about to get a new path to target LNG export demand at Cheniere Energy’s Sabine Pass LNG terminal. Cheniere in late December received federal approval to commission its new Sabine Pass lateral—the 2.1-Bcf/d East Meter Pipeline. Also in late December, Williams indicated in a regulatory filing that it anticipates a February 1, 2017 in-service date for its 1.2-Bcf/d Gulf Trace Expansion Project, which will reverse southern portions of the Transcontinental Gas Pipe Line to send Northeast supply south to the export facility via the East Meter pipe. Today we provide an update on current and upcoming pipelines supplying exports from Sabine Pass.
As U.S. crude oil and natural gas market prices and rig counts climb, the SCOOP and STACK in central Oklahoma continue to be two of the handful of plays attracting significant increased activity and investment, both on the producer and midstream sides. Production growth from the 11-county region covering the two plays is helping to offset declines in oil and gas volumes from other parts of Oklahoma and the Midcontinent region as a whole. Today we look at historical and recent drilling activity as an indicator of potential growth.