Each winter, New York spot prices for gasoline and diesel spike higher than spot prices in Chicago, opening a seasonal arbitrage opportunity for Midwest refineries and motor fuel marketers—if only they could move more product east from Petroleum Administration for Defense District (PADD) 2 to the East Coast’s PADD 1. Midstream companies have taken note, and have been adding eastbound refined product pipeline capacity in Ohio and Pennsylvania. So far the aim has been to move gasoline and diesel as far east as central Pennsylvania, but the longer-term goal seems to Philadelphia, which ironically is the center of East Coast refining. Today we look at the ongoing shift in market territories claimed and sought by gasoline and diesel refineries and marketers in PADDs 1 and 2.
Daily Energy Blog
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.
In 2015, Sooners held on tight as Oklahoma was rocked by 890 earthquakes with a magnitude of 3 or higher—up sharply from only 43 earthquakes in 2010 and an average of less than two earthquakes per year in the previous quarter-century. Oklahomans have experienced hundreds of earthquakes this year too, including a record-breaking 5.8 event on September 3 and, on November 6, a 5.0 quake very near Cushing, OK, which serves as the delivery point for the CME/NYMEX Light Sweet Crude contract and which has earned the nickname “Pipeline Crossroads of the World”. Today we look at the latest quake near Cushing and other recent pipeline disruptions to assess the resilience of critical crude-delivery systems.
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.
Mexico’s consumption of motor fuels is rising, its production of gasoline and diesel continues to fall, and U.S. refineries and midstream companies are racing to fill the widening gap. The export volumes are impressive: deliveries of finished motor gasoline from the U.S. to Mexico averaged 328 Mb/d in the third quarter of 2016, up 41% from the same period last year, and exports of low-sulfur diesel were up 29% to 194 Mb/d. And there’s good reason to believe that U.S.-to-Mexico volumes will keep growing. Today we look at recent trends in gasoline and diesel production and consumption south of the border, and at ongoing efforts to enable more U.S.-sourced gasoline and diesel to reach key Mexican markets by rail and pipeline.
It’s been a tough few years for Canadian oil producers. As they ramped up production in the oil sands, Canadian E&Ps faced pipeline takeaway constraints that drove down the price of Western Canadian Select versus Gulf Coast crudes. The Keystone XL pipeline would have largely solved things, but when that project was killed by Canada’s U.S. friends and neighbors, oil sands producers had to settle for a series of smaller, more incremental projects that provided only a partial fix. The devastating Alberta fires of May 2016 reduced production and pretty much eliminated constraints for much of this year. But volumes have recovered, and if oil sands production is to continue growing, more pipelines and new customers will be needed. Today we consider Canada’s long-running effort to ensure there’s enough capacity to move its crude to market, two major projects that just won the backing of the Canadian government, and what may be next.
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.
OPEC’s agreement at its November 30 meeting to cut crude oil output has sent prices soaring. Many U.S. producers already are anticipating brighter days, but before anyone pops the champagne it’s important to consider the deal’s potential vulnerabilities, and to factor in other market developments that reduce the agreement’s effect. Today we look at pre-deal maneuvering, the impact of those maneuvers on the level of supply, and the things that could still derail the move to market equilibrium.
On November 17, 2016, Tesoro Corp., the second-largest independent refiner in the Western U.S., announced an agreement to acquire Western Refining for an estimated $6.4 billion. This is the second acquisition that Tesoro has made this year, following the purchase of the MDU Resources/Calumet Specialty Products Partners’ joint venture refinery in North Dakota. And—ironically, considering the name of the company Tesoro is buying—the Western Refining deal will expand Tesoro’s footprint further east than ever. Today we evaluate the legacy assets of Tesoro and Western Refining and discuss how the two companies will likely fit together.
The frac spread—the difference between the value of a typical basket of NGLs and the price of natural gas, in $/MMBtu—has averaged a paltry $2.28 for the past two years, by far the longest period of depressed NGL values since the start of the Shale Revolution. That’s bad news for natural gas processing economics, which are most favorable when NGL prices are strong and natural gas prices are weak. But things are about to get a lot better. Today we consider the currently low frac spread, what it means for natural gas producers and processors, and why a big turnaround may be in the offing.
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.
