Current analysis of how Western Canadian producers can find supplies to meet a growing need for diluent material to blend with their heavy crude and bitumen suggest that up to 485 Mb/d of imports will be needed by 2019. But there is a growing belief that increased production of condensate from the Montney and Duvernay shale plays in Western Alberta and British Columbia will supply far more diluent than previously expected – reducing that import requirement significantly. Today we look at plans by Pembina to ship increased diluent supplies to Edmonton from domestic Canadian sources.
We enter the natural gas winter this November after a record-breaking storage season that saw 2.75 Tcf of summer surplus squirreled away into underground storage. That surplus resulted from record breaking U.S. production exceeding lower summer demand. This year a repeat of last year’s freezing winter should run down storage enough to leave room for another summer of surplus. But with U.S. production at 70 Bcf/d and northeast output up 22 percent this year to nearly 18 Bcf/d gas supplies have reached a level where anything but a cold winter will leave too much gas in the ground next March. That theoretically would leave no room to inject surplus supplies into storage next summer – threatening the balancing role that storage plays in the natural gas market. Today we explain how the gas supply demand balance is threatened by changes to the storage market.
Last week Eagle Ford producer BHP Billiton – apparently tired of waiting for a ruling from the Department of Commerce Bureau of Industry and Security (BIS) – decided to export a cargo of processed condensate that they have “self-classified” as refined product – meaning it is not subject to U.S. export restrictions on lease condensate and crude oil. That move followed BIS approval for Enterprise and Pioneer to make similar exports in July 2014 and could set off a posse of similar condensate exports by Eagle Ford producers. Today we review new market options for condensate producers.
Crude prices have been at three-year lows this week as the world appears to be awash with supplies. With OPEC apparently not willing to defend higher prices by reducing their output, attention has turned to the likely impact on U.S. shale production of a lower price regime. Today we explore why shale production is unlikely to slow down rapidly and may even increase as producers move rigs to plays with higher returns.
The Edmonton region in Alberta is home to a growing crude gathering hub that brings in bitumen crude from the oil sands region 250 miles to the north. In order to get that crude to Edmonton and to markets in the U.S., producers must first blend it with diluent range materials so that it can flow in pipelines. In the early days much of the diluent required in the oil sands was delivered by rail and truck but now a growing “parallel” pipeline network is developing to source and distribute supplies as new production comes online. Today we look at the Edmonton diluent distribution system.
There’s good reason to be bullish about a skyrocketing trajectory for US methanol production. Natural gas prices are relatively low and likely to stay so; domestic demand for methanol continues to increase; and overseas demand—especially in China—is rising even faster. More than a dozen methanol mega-projects are in various stages of planning, design and construction, most of them along the Gulf Coast. If they were all built (they probably won’t be), US methanol production capacity would increase more than 10-fold to nearly 30 million metric tons per year, and turn the US from a methanol importer to an exporter within two or three years. Today, we look into why methanol demand is rising, what new capacity is under development in the US, and what it all means for natural gas producers.
Since the start of 2013 Corpus Christi marine terminal facilities have increased crude and condensate storage by 10 MMBbl and throughput capacity from 225 Mb/d to nearly 1 MMb/d. Upwards of 700 Mb/d is leaving the Port of Corpus Christi by barge and tanker – most of it headed along the Gulf Coast to Houston or Louisiana. Waterborne traffic congestion in Corpus is already limiting terminal throughput but the potential for increased exports of condensate and refined products from planned condensate splitters suggest the traffic will get worse soon. Today we survey current Corpus terminal facilities.
There is an onslaught of surplus natural gas supply bearing down on the Henry Hub in South Louisiana. More than 60 natural gas pipeline projects are in the process of reversing the continent's gas flows to move gas out of the Northeast, and much of that production will be moved to the Gulf Coast. That gas will slam into supplies moving in to Louisiana from the west, sourced from “wet” gas and associated gas from crude oil plays in TX, NM, OK and ND. Demand from gas fired power generation, industrial gas use and LNG exports will eventually absorb the incremental supply, but not for a few years. We’ve seen this movie before, in the 2008-10 timeframe when Rockies gas battled it out with new shale supplies from the Haynesville and Fayetteville. But this time there is a big difference in the economics of production. Today we summarize the conclusions from a new deep-dive report from RBN Energy and BTU Analytics.
Japan is the world’s leading importer of liquefied natural gas, and its dependence on LNG has only increased since the March 2011 Fukushima nuclear disaster, which led to the shutdown of Japan’s 48 nuclear units. Some of those nukes are expected to return to service starting in 2015, but it’s possible—some would say likely—that a quarter or maybe even half of Japan’s nuclear fleet will never be restarted. While coal is cheap and oil is cheaper than it was a few months ago, natural gas-fired generation is seen as the best short-, mid- and long-term substitute for nuclear power. As a result, Japan utilities are working to increase and geographically diversify their LNG purchases, and to break what for decades has been a link between the pricing of LNG and oil. Today, we continue our look at how Japan’s response to the Fukushima disaster affects U.S. and Canadian natural gas producers and LNG exporters.
Canadian production of diluent range light hydrocarbon materials such as natural gasoline and condensate are not currently meeting demand from the oil sands region. Diluent is used to reduce the viscosity of heavy Canadian crude so that it can flow to market in pipelines. Diluent supplies required to supplement Canada’s domestic output are nearly all imported from the U.S. via two pipelines that originate in the Midwest. Those pipelines are mostly supplied with diluent sourced from the Gulf Coast. Today we look at how imported diluent gets to Western Canada.
It seems increasingly likely that Hawaii’s electric utility and gas utility will be leading the Aloha State through a multi-year transition from an oil-based economy to one founded largely on liquefied natural gas—most of it sourced from Western Canada. Hawaii Gas, which currently makes syngas from naphtha, has proposed a two-step transition to LNG that begins with ISO container shipments and follows up with bulk shipments. That meshes well with Hawaiian Electric’s plan—also a two-stepper. Today, we up update our recent series on Hawaii’s big-wave move to LNG-based natural gas.
Refineries located close to booming Eagle Ford shale production have nameplate capacity to process over 900 Mb/d of crude but can only consume 375 Mb/d of local output today. That is because the larger refineries in Corpus Christi were built to process heavy sour crude oil instead of ultra light Eagle Ford. New additions will expand light crude capacity by 100 Mb/d in 2015 (in addition to planned condensate splitters). Today we detail Devon and Genesis pipeline projects as well as regional refining capacity.
If 2012 was “the year of the tank car” in North Dakota then 2014 could turn out to be the year when crude by rail economics turned sour for producers. New pipelines are coming online to deliver increased volumes of crude to the Gulf Coast with more projects on the drawing board. Safety issues and traffic congestion are raising the cost of rail freight. But the biggest challenge to rail is the pressure from narrowing crude price differentials between North Dakota and coastal markets. Producers can now get better returns shipping barrels by pipeline and in a falling price market they are more incented to make the switch. Today we explain why rail may be losing its edge.
New pipeline projects to take crude out of the Rockies are starting to make the map look like a spider’s web. The latest proposal comes from Spectra Energy – owners of the Express and Platte pipelines that ship crude from Hardisty to Wood River via Guernsey, WY. Spectra hope to build a pipeline carrying light sweet crude from Guernsey to the Midwest pipeline hub at Patoka. The project would bypass Cushing and push more light crude to the east with potential access to Midwest refineries or even the East Coast. Patoka is also poised to become an origination point for shipments to the Gulf Coast. Today we review the Spectra project’s chances in a crowded pipeline field.
Demand for diluent range light hydrocarbon materials such as natural gasoline and condensate that are used to reduce the viscosity of heavy Canadian bitumen crude so that it can flow in pipelines, is forecast to increase from 380 Mb/d in 2014 to 685 Mb/d by 2019. Increasing bitumen crude production in the Western Canadian oil sands region drives that demand. New large scale bitumen projects in Alberta requires two pipelines – one to ship crude production to market and one to ship in diluent for blending. Today we start a new series detailing the expanding western Canadian diluent distribution network.