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.
The build-out of incremental natural gas takeaway capacity out of the Marcellus/Utica region has come in fits and starts, with new pipelines—as opposed to the reversal or expansion of existing pipes—proving to be the most troublesome. Energy Transfer Partners and Traverse Midstream Holdings’ long-planned 3.25-Bcf/d Rover Pipeline to southern Michigan is a case in point. The latest challenge for the $4.2 billion project is getting final federal approval in time to allow tree clearing along the pipeline’s 711-mile route to be completed before federally protected bats start roosting in early April. If that timeline’s not met, Rover’s planned completion later in 2017 may be delayed a full year, enabling Western Canadian gas producers to sell more gas to Ontario and the Upper Midwest. Today we assess what’s at stake for ETP, Traverse, and producer-shippers in the Marcellus/Utica and Western Canada.
There’s good reason to believe that the international LNG market has turned a corner, with demand and LNG prices on the rise and with a number of new LNG-import projects being planned. That would be good news for U.S. natural gas producers, who know that rising LNG exports will boost gas demand and support attractive gas prices. It also would help to validate the wisdom of building all that liquefaction/LNG export capacity now nearing completion. Today we look at recent developments in worldwide LNG demand and pricing and how they may signal the need for more LNG-producing capacity in the first half of the 2020s.
The SCOOP and STACK combo play in central Oklahoma recently has emerged as one of the most prolific and attractive shale production regions in the U.S. Like the Permian Basin (albeit on a much smaller scale), rig counts in this play have weathered the crude oil price decline better than most of the rest and, along with the Permian, are leading a rebound as prices move higher. These days, SCOOP/STACK producers are primarily targeting crude oil and condensates, but the area also is seeing a resurgence of natural gas output from associated gas. More than that, given its economics, location and ample infrastructure, gas supply from the region has the potential to be directly competitive with Marcellus/Utica supply. Today, we begin a series analyzing production trends in the SCOOP/STACK, with a focus on natural gas.
The CME/NYMEX Henry Hub January contract settled yesterday at $3.54/MMBtu, about 30.8 cents (~10%) above where the December contract expired ($3.232) and 77.6 cents (28%) higher than where November settled ($2.764). The natural gas winter withdrawal season is officially underway—it’s a lot colder and gas demand has spiked. But this week also marks another key bullish threshold: as today’s Energy Information Administration (EIA) storage report will likely show, the U.S. natural gas inventory has fallen below the prior year’s levels for the first time in two years (since early December 2014). That’s in sharp contrast to where the inventory started the injection season in April—more than 1,000 Bcf higher compared to April 2015. Moreover, we expect the emerging deficit to grow substantially over the next several weeks. Today we look at the supply-demand fundamentals driving this shift and what it means for the winter gas market.
The Western states continue to ramp up their renewable energy mandates—California and Oregon, for instance, plan to get at least 50% of their electricity from renewable sources, and Colorado has set a 30% requirement. Ironically, this renewable energy trend puts a spotlight on natural gas, whose at-the-ready supply will be needed to fuel the West’s increasing number of gas-fired power plants at a moment’s notice to offset the up-and-down output of solar facilities and wind farms. One way to help ensure natural gas availability is have gas storage capacity close at hand. Today we look at ongoing efforts to add tens of billions of cubic feet of natural gas storage in the Western U.S., primarily to help ensure the fueling of nearby gas-fired power plants that back up variable-output solar and wind.
Of the six interstate pipelines that account for most of the natural gas crossing the Texas/Louisiana state line, two have net flows that are westbound into Texas––something that would have been unthinkable just a few years ago. By the end of this decade—and maybe far sooner—Texas will be receiving more gas from Louisiana than vice versa, mostly due to planned pipeline reversals aimed at moving more Marcellus/Utica gas to Texas export markets. Today we continue our look at changing Texas gas flows, this time with a focus on the half-dozen most important pipelines at the Texas/Louisiana border.
Takeaway capacity out of the Marcellus/Utica shale producing region is about to get another significant boost. Tallgrass Energy’s Rockies Express Pipeline (REX) expects to bring the first 200 MMcf/d of its 800-MMcf/d Zone 3 Capacity Enhancement project (Z3CE) in service any day now, and ramp up to the full 800 MMcf/d by end of the year. Moreover, the pipeline operator has hinted that it may be able to eke out incremental Zone 3 operating capacity over and above the new design capacity in the near future. The Z3CE expansion will mark the third time in as many years that REX will increase westbound takeaway capacity out of the Marcellus/Utica region. With each capacity boost, Northeast production volumes have risen to the occasion and the capacity has filled up. Today we examine this latest expansion and what it will mean for U.S. gas production.
The U.S. natural gas market in the past two years has undergone massive change, from breaking storage records and crossing long-held thresholds to flipping flow patterns and pricing relationships on their heads. This November, the market crossed yet another milestone: the U.S. became a net exporter of natural gas for the first time ever on September 1, 2016. That lasted only a few days. But net exports resumed again starting November 1 and have continued through the month, almost without interruption, with pipeline deliveries to Mexico and to the first two liquefaction “trains” at Cheniere Energy’s Sabine Pass LNG terminal exceeding imports from Canada and LNG import terminals by an average 0.6 Bcf/d. Today, we look into what’s really driving this shift and what that tells us about the trend going forward.
Every day, crude oil producers on Alaska’s North Slope re-inject nearly 7.8 Bcf of natural gas into their wells, enough gas to supply the entire U.S. West Coast—California, Oregon and Washington State. If only there were some way to monetize that gas supply, to move it to market. The problem is that there isn’t, at least in today’s gas/LNG market, which is characterized by ample supply and relatively low prices. This same market also favors infrastructure projects that are simple and low-cost; no one wants to make multibillion-dollar commitments when natural gas prices and margins are so low. Today we conclude our series on the tough times ahead for Alaska’s energy sector with a look at the state’s vast natural gas reserves and the challenges associated with tapping them.
The natural gas flow patterns that characterized the U.S. energy-delivery sector for the decades preceding the Shale Revolution are gradually being undone, and few, if any, states are more affected by these changes than Texas. The state remains the nation’s largest natural gas producer, and it still produces nearly twice as much gas as its consumes within its borders. But traditional Northeast and Midwest markets for Texas gas are being ceded to Marcellus/Utica producers, and more and more Northeast gas is flowing south/southwest to the western Gulf Coast, drawn by power/industrial demand, new LNG export terminals and rising pipeline-gas exports to Mexico. Today we begin a look at the dramatic shifts in gas flows out of Texas through key gas pipeline exit points.
Demand for U.S. natural gas exports via Texas is set to increase by close to 6 Bcf/d over the next few years. At the same time, Texas production has declined more than 3.0 Bcf/d (16%) to less than 17 Bcf/d in the first half of November from a peak of over 20 Bcf/d in December 2014, and any upside from current levels is likely to be far outpaced by that export demand growth. Much of the supply for export demand from Texas will need to come from outside the state, the most likely source being the only still-growing supply regions—the Marcellus/Utica shales in the U.S. Northeast. Perryville Hub in northeastern Louisiana will be a key waystation for southbound flows from the Marcellus/Utica to target these export markets along the Louisiana and Texas Gulf Coast, particularly given the hub’s connectivity and prime location. Today, we look at the pipeline expansion projects into Perryville that will make this flow reversal possible.