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.
The SCOOP and STACK plays in central Oklahoma have emerged as two of the most productive and cost-effective plays in the entire U.S. Rigs are returning, crude oil production is rising, and so is production of associated natural gas. Moreover, the RBN production economics model shows that SCOOP and STACK will continue to be attractive to drillers under all of our various price scenarios—even if crude were to slip back below $50 and natural gas goes back into the dog house, where it has been headed the past few days. Today we continue our look at the side-by-side Sooner State plays with a review of existing and planned gas processing capacity.
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.
As it builds out the nation’s oil and natural gas pipeline networks to keep pace with ever-changing needs, the midstream sector has faced a number of challenges, perhaps chief among them regulatory delays exacerbated by organized environmental opposition. An oft-repeated priority of the new administration has been to make it easier to advance the development of new energy infrastructure development. That raises a few questions. How much difference will this apparent change in attitude make? Should we expect a huge surge in new pipeline projects to be approved and move forward? Today we examine major projects that have faced drawn-out approval processes and evaluate the degree to which a new administration can grease the skids for new pipelines.
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.
So far, relatively mild weather this winter has insulated New England natural gas consumers from pipeline capacity-related price spikes that occurred during cold snaps in previous winters. And even if another polar vortex were to happen, it’s likely the regional electric grid operator’s Winter Reliability Program to shift gas-fired generators from pipeline gas to stockpiled oil or LNG would keep the lights on. But New England’s day of reckoning is coming. The region is becoming ever-more dependent on gas-fired power, most gas pipeline projects into New England are stalled or scrapped, and New York’s recently announced plan to close two Indian Point nuclear units will only make matters worse. Today we discuss the still-widening gap between Northeast pipeline capacity and gas demand.
As natural gas exports to Mexico continue to rise and as construction proceeds on Texas liquefaction/LNG export terminals, the day is approaching when Texas will flip from being a net producing region to being (with exports) a net demand region. Fortunately, supplies from elsewhere are readily available to meet that demand—sourced from the Marcellus/Utica and moving on new and reversed pipeline capacity to the Gulf Coast. A good portion of that gas must traverse “miles and miles of Texas” to meet the burgeoning export demand at the Agua Dulce hub near Corpus Christi, a location that is emerging as a key pricing point for the South Texas gas market. But a potential problem is looming: There may not be enough pipeline capacity available to meet that demand, with important implications for South Texas prices, flows and natural gas export volumes. The average annual basis at Agua Dulce could increase to as much as a dime ($0.10/MMbtu) above Henry Hub in 2020 from its historical level $0.02/MMbtu to $0.05/MMbtu below Henry. Today we discuss these and other highlights from the fourth and final part of RBN’s Drill Down series.
As natural gas exports to Mexico continue to rise and as construction proceeds on liquefaction/LNG export terminals in Freeport and Corpus Christi, TX, the need to transport increasing volumes of gas down the Texas Gulf Coast becomes ever more urgent. And moving gas down the coast is no easy task; the Lone Star State’s convoluted mix of interstate and intrastate pipelines were designed primarily to flow gas up the coast from South Texas and Gulf Coast production areas to the greater Houston Ship Channel area—and from there on interstate pipes to Louisiana and beyond. Today we use RBN’s Fretboard Model to discuss whether existing and planned southbound pipeline capacity will be sufficient to meet export demand.
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.
Crude oil and natural gas production growth stalled in 2015 and has declined this year in some of the big shale basins. But we may be seeing a turnaround. The latest EIA Drilling Productivity Report, released on December 12, 2016, included upward revisions to its recent shale production estimates and also projects an increase in its one-month outlook for the first time in 21 months (since its March 2015 report). Today we break down the latest DPR data.