Handling the flood of Marcellus/Utica gas headed to Gulf Coast LNG export terminals and to Mexico will require pipeline reversals and expansions, new pipe and a coordination of interstate and intrastate pipeline capacity. That’s a tall order in itself, but there’s more: Texas’s intrastate pipelines operate under an entirely different set of regulations than their interstate counterparts––different rules on pipeline tariff rates, pipeline rules, permitting, eminent domain, you name it. In today’s blog we continue our look at developmental history of the Lone Star State’s two gas pipeline systems––one regulated in Washington, DC and the other in Austin––and how it may affect the transformation of the overall natural gas transportation grid.
Texas’s vast natural gas pipeline network is undergoing a major transformation to enable gas from the Marcellus/Utica shale plays to flood south/southwest into and through Texas to LNG export terminals and to Mexico. To grasp the complexity of the task at hand, it is critically important to understand how Texas’s “spaghetti bowl” of interstate and intrastate pipeline systems evolved in parallel but under very different regulatory constructs, and with the intention of serving very different market needs. In today’s blog, we begin an examination of the state’s two pipeline systems––one regulated by the Feds in Washington, DC and the other by the Texas Railroad Commission in Austin, TX––and why the intrastate system has taken on a new significance for U.S. natural gas markets.
Net crude oil imports to the U.S. Gulf Coast in 2016 have been running well above the pace set last year, the increase driven by a combination of lower U.S. crude oil production, rising import levels and relatively flat export volumes. The trend toward higher net imports –– an outgrowth of the end of the ban on U.S. crude exports –– is significant in that it affects oil inventories and oil prices. What’s driving this trend, and how soon might net imports peak? Today, we survey recent developments on the crude oil import/export front, with a focus on the Gulf Coast.
Of all the demand markets in the U.S., the biggest prize eyed by Marcellus/Utica natural gas producers is the Gulf Coast region, where a combination of industrial demand, LNG exports and power generation projects is driving a need for more and more gas. And beyond the U.S. Gulf Coast states, there lies still another market capable of gobbling up even more of the excess Northeast gas supply: Mexico’s rapidly growing gas-fired generation sector ––that is, assuming pipelines in Texas can get it all the way there. There is over 4.0 Bcf/d of Marcellus/Utica-to-Gulf-Coast takeaway capacity planned to be completed over the next few years. Today, we look at the status and timing of Northeast pipeline takeaway projects targeting the Gulf Coast.
Until a few years ago, a good bit of the natural gas produced along the Gulf Coast was piped long-distance to warm homes and businesses in the Northeast and the Midwest. Now, though, cheap-to-produce Marcellus and Utica shale gas has come to dominate gas heating and power markets from Boston to Cleveland, and Northeast-sourced gas is starting to move into Louisiana and Texas, competing head-to-head with Gulf Coast production. With Marcellus/Utica gas production in ascendance, what will be the fate of all the gas still being produced along the U.S. Gulf Coast? That’s the subject of RBN’s latest Drill Down Report, highlighted in today’s blog, which describes the battle lines being drawn and the important roles LNG exports and Mexican demand will play in keeping U.S. gas markets in balance.
After the $5 billion-plus expansion of the Panama Canal is dedicated this Sunday, June 26, the first “New Panamax” vessel scheduled to pass through the canal’s new, longer, wider locks will be the Lycaste Peace, a Very Large Gas Carrier (VLGC) that is transporting propane from Enterprise Products Partners’ Houston Ship Channel export terminal to Tokyo Bay in Japan. What remains to be seen, though, is how many other supersized vessels carrying propane, liquefied natural gas (LNG) or other hydrocarbons will follow, and how soon. Today, we mark the formal opening of the newly enlarged Atlantic-Pacific short-cut with a look both at the game-changing potential of the expanded canal and the realities of today’s energy and shipping markets.
More new crude oil storage capacity came online in the U.S. in the fourth quarter of 2015 and the first quarter of 2016 than in any half-year period in memory, and still more capacity is being planned. Even with all this new capacity—and the slowdown in crude oil production—the storage utilization rates at Midwest/Mid-continent and Gulf Coast tank farms, underground salt caverns and refineries are at or near record highs too. And tens of millions more barrels of storage capacity are on the drawing boards in anticipation of further incremental needs. But the energy sector is pulling back, right? What gives? Today, we begin an update on crude storage trends and crude storage facilities in Petroleum Administration for Defense Districts (PADDs) 2 and 3, which together account for 82% of U.S. crude storage capacity.
In February 2016, two months or so after the U.S. lifted its crude oil export ban, prices hit their lowest point in the current down-cycle that began in the summer of 2014. The ongoing price collapse had contributed to the favorable political winds in Washington, DC that resulted in lifting the ban. But what was favorable in the political realm posed severe commercial difficulties: U.S. producers were stuck with trying to sell into an international market awash in crude. Facing adversity, though, U.S. exporters have been getting creative, with the latest strategy involving backhauls of U.S. crudes on the same ships delivering foreign crude to U.S. ports. In today's blog, ClipperData's Abudi Zein looks at the market conditions that make such crude flows economically rational.
A few years back, crude-by-rail (CBR) emerged as the go-to fix that enabled pipeline-constrained shale regions to move fast-increasing volumes of oil to market. A total of 178 rail terminals were built or significantly expanded, with 99 loading terminals and 79 unloading terminals developed in the U.S. and Canada. But changes in the market -- lower oil prices, slowing/declining production, new pipeline capacity -- have been challenging and undermining CBR. Only about 20% of U.S. nameplate capacity is being used, and further declines in CBR volumes are expected, prompting serious questions about CBR’s future role. Today, we discuss RBN Energy’s latest Drill Down Report, which examines CBR’s pros and cons, its evolution, and its current status and prospects.
The story of crude-by-rail (CBR) in North America is that of a victory of good old U.S. ingenuity over the lack of pipeline capacity that stranded booming shale oil production in 2012. The lower cost to market of “on-ramp” rail terminals allowed surging crude production a route to (mainly) coastal refineries - igniting a building boom over 4 short years that has left 82 load terminals and 44 destination terminals operating today - many of them now underutilized. Along the way monthly lease rates for rail tank cars that reached $2,750/month at the height of the boom are down to $325/month after the bust – with many lease holders paying daily rent to park their empty cars. Today we conclude our series reviewing the state of CBR today.
Our analysis shows that about 1.7 MMb/d of crude-by-rail (CBR) unload capacity has been built out and is operating in the Gulf Coast region today. According to Energy Information Administration (EIA) data for January 2016 an average of only 142 Mb/d was shipped into the region by rail in January 2016 down from a peak of just under 450 Mb/d in 2013 and an average of 235 Mb/d in 2015. In other words, the current unload capacity represents a whopping 12 times January 2016 shipments – a massive overbuild that is continuing today as new terminals are still planned. Today we look at the fate of Gulf Coast CBR terminal unload capacity.
According to our friends at Genscape at the end of March (week ending April 1, 2016) Bakken shippers could sell their crude at the railhead in North Dakota for $32.05/Bbl. Prices for Light Louisiana Sweet (LLS) crude at the Gulf Coast were about $5.40/Bbl higher than at the railhead but the rail freight to the Gulf was a few cents less than $12/Bbl. That means a Bakken producer would lose nearly $6.50/Bbl by shipping crude by rail to St. James, LA versus selling in North Dakota. Yet despite Crude-by-Rail (CBR) economics being so underwater - the volumes delivered to two St. James terminals averaged 66 Mb/d in 2016 through March. Today we continue our series on the fate of CBR with a look at inbound Gulf Coast CBR shipments.
Waterborne crude volumes (including imports) delivered to coastal refineries in Texas, Louisiana and Mississippi by domestic producers peaked at 27% of inputs in 2014 as regional plants processed increasing quantities of shale crude. Since then, these volumes have plummeted to 15% of inputs in March 2016 as Gulf Coast refiners have returned to more competitive imports instead. At the same time Eagle Ford crude volumes shipped along the Gulf Coast have fallen 28% this year in response to declining production and narrow price differentials between Texas and Louisiana ports. Gulf Eagle Ford crude now also plays a far smaller part in export markets than WTI grades. Overall exports have not increased since the end of the export ban but volumes to Canada have plummeted as shipments to other nations have increased. Today we review the shifts in waterborne flows across the Gulf Coast region.
Most of the gasoline, diesel, heating oil and jet fuel consumed in the U.S. East Coast region is piped in via long-distance pipelines from Gulf Coast refineries, but substantial amounts are moved in by ship—either from the Gulf Coast by Jones Act vessels or from overseas. These shipped-in volumes then need to make their way from port to consumer. Today we continue our examination of how transportation fuels and heating oil are delivered to East Coast users with a look at the ports and connecting pipelines that help move these critically important fuels.
The East Coast consumes more than 200 million gallons of gasoline, diesel, heating oil and jet fuel a day, but produces only one-fifth of that total, most of it at New Jersey and Pennsylvania refineries. To keep the region’s cars, trucks, trains and airplanes moving (and many of its homes and businesses heated) huge volumes of fuels need to be delivered from elsewhere, mostly via two pipelines from the Gulf Coast and the rest by ship—some from Gulf and other U.S. ports and some from overseas. Today, we continue our examination of the infrastructure that moves gasoline, diesel, heating oil and jet fuel to the nation’s largest fuel-consuming region with a look at four major pipelines.