China has got a lot of shale gas. To the tune of 1,275 Tcf of technically recoverable shale reserves, by some estimates. But today it is all still sitting in the ground. If that potential is tapped in any significant way, it will have a huge impact on global gas balances, with implications for LNG markets, economic competitiveness and geopolitical clout. But a lot of obstacles must be removed before the promise of Chinese shale gas can be realized. Last week I spoke at the Global Unconventional Gas Summit, held in Beijing. After listening to two days of presentations on the issues, I came away with the view that while some of these barriers are inherent in the Chinese system, probably the biggest barrier is a general misunderstanding of why shale gas developed the way it did in the U.S. in the first place. So today we will provide a small window into the Chinese shale gas initiative and in the process learn something about the real drivers of shale gas development here in the U.S.
Daily Energy Blog
The CME NYMEX WTI crude futures contract is the underlying benchmark in nearly all US domestic crude price contracts. Differences between futures and physical trading arrangements make pricing physical WTI barrels complex. Two formula mechanisms are commonly used in physical transactions that link directly to the NYMEX settlement prices – the CMA average and WTI P-Plus. Today we conclude a two-part look at WTI spot crude pricing.
There is a close, symbiotic relationship between brine and natural gas liquids. Most NGL storage is in huge underground caverns washed out of salt formations thousands of feet below the surface. That washing or ‘leaching’ process makes lots of brine. When the storage caverns or wells go into service, the NGLs replace the brine. But when NGLs are removed from the wells, brine must displace the NGL barrels. Nowhere is this relationship between brine and NGLs more entwined with the history of the facilities than at Bumstead and Adamana, two storage facilities in Arizona. Today we continue our series looking at the unique niche these two operations fill in the NGL marketplace and where they may be headed in the future.
Northeast bound interstate natural gas pipeline companies are busy reconfiguring their assets to accommodate significant supply growth expected by 2017. At the same time, regional natural gas supply and distribution companies are taking advantage of the opportunities that new local production brings.
We’ve talked a lot here about NGL storage in Mont Belvieu and Conway. Those are the big underground storage caverns washed out of salt formations thousands of feet below the surface. But those are not the only places where NGLs are stored in underground salt caverns. Two important facilities, especially for West Coast NGL markets are located in the seemingly unlikely locations of Bumstead, AZ and Adamana, AZ. Today and in a later follow up we’ll look at why these facilities are in Arizona, how they got there, and the unique niche they fill in the NGL marketplace.
NYMEX WTI is the most liquid commodity future in the world. So far this year the exchange traded an average 125 MMb/d in the prompt contract alone. The NYMEX crude price is so ubiquitous that it also underpins the domestic US crude spot market. Differences between futures and physical trading as well as the delivery mechanism that links the two markets, make pricing physical WTI complicated. Today we begin a two-part look at US spot crude pricing.
Growing propane production from the NGL surge is building up inventories and pushing down prices because it can’t reach markets where demand is increasing. That story probably sounds familiar to crude and natural gas producers actively looking for opportunities to export their way around production overhangs. However, unlike crude and natural gas (or condensate) there are no regulatory barriers to prevent US propane exports. Today we look at how exports will balance growing supplies in the propane market.
Northeast regional interstate pipeline companies are coming to terms with significant supply growth expected between now and 2017. Companies that traditionally delivered natural gas to the Northeast from outside the region are busy reconfiguring their assets.
In two previous postings in this series we examined the major infrastructure projects being developed by interstate natural gas pipelines in response to the growth of Northeast natural gas production in the Marcellus shale. We reviewed projects developed by Tennessee Gas Pipeline (TGP), and then Spectra Energy (see TGP and Spectra). This time we look at the projects being pursued by Williams Companies through it Transcontinental Gas Pipeline Company (Transco) and its Master Limited Partnership (MLP) Williams Partners.
Our thoughts and prayers are with the families and friends of those who lost their lives to Hurricane Sandy and to those dealing with the aftermath of the storm. |
On Monday as record setting Hurricane Sandy was plowing into the East Coast, another record was quietly being broken. That record was all time U.S. natural gas production. According to Bentek numbers it increased to 64.9 Bcf/d (total natural gas production less NGLs and other shrinkage, lower 48 states). It is kind of spooky that this occurred just before Halloween. That’s because back in August we noted that Halloween could be an important date for natural gas production. It turns out that is true, but not for the reasons we thought at the time. So today we return to our original analysis to see what has changed and examine the consequences for the upcoming natural gas heating season.
US domestic crude oil production took off in the past year. Most of the production growth is coming from three shale oil plays – the Bakken, Eagle Ford and Permian basins. A number of factors have combined to allow rising production to continue. Today we review what sustains increased crude production and whether it can continue.
The chart below shows total US domestic crude production since the start of 2009. Around August 2011, the level of production started to ramp up dramatically. Despite a brief respite when crude prices fell below $80 / Bbl earlier this year, production is rising again. The latest data from the Energy Information Administration (EIA) shows that between September 2011 and July 2012, production increased from 5.6 MMb/d to 6.3 MMb/d - that’s a 62 Mb/d production increase every month.
The specialized corporate structures called Master Limited Partnerships (MLP’s) have become part of the landscape for midstream energy companies. They have helped provide efficient access to investment capital to build out infrastructure that is now delivering new shale basin natural gas and oil production to market. MLP investors have enjoyed high yield returns from these tax-advantaged companies with low risk toll road income. Newer MLP structures appear to be moving away from the safety of toll road income into riskier commodity price exposure. Today we investigate this trend in the MLP market.
The gasoline market has become highly regionalized with the country apparently divided into areas of feast and famine. Shortages, low margins and declining refinery capacity have plagued the Northeast and California. Increased gasoline exports have rewarded Gulf Coast refiners. Midwest and Rocky Mountain refiners have profited from strong refining margins.
Growing condensate supplies from tight oil shale plays are sloshing up at Gulf Coast refineries and being discounted by refiners that don’t need more of the ultra-light crude. Meanwhile there are established international markets for condensate. The resolution seems obvious – just export the surplus condensate and import the kinds of crude oil needed by Gulf Coast refineries. That’s likely okay if the export destination is Canada for use as bitumen diluent, but there is a finite limit to that market. However exporting raw condensate to destinations outside North America is particularly tricky under U.S. crude-oil export restrictions. Today we delve into the nuances of what the export rules say and what the market is doing to deal with these regulations.
Last week we introduced a blog series from contributor Ann Davis Vaughan on condensates – the hydrocarbon mixture that is now being produced from tight oil shale plays in increasing quantities. That production surge is causing refiners and traders to scratch their heads figuring out the best uses and markets for condensate. We quickly found that our efforts to understand the condensate market were being hampered by definitions as varied as Lady Gaga’s outfits.
On Friday (October 19, 2012), West Texas Intermediate (WTI) crude futures for delivery at Cushing, OK closed at $90.05/Bbl – some $20 below the price for the similar grade Light Louisiana Sweet (LLS) crude sold at the Gulf Coast. We believe that price differential will fall as new supplies of domestic and Canadian crude find their way to the Gulf Coast next year (2013). Supplies of South Texas Eagle Ford are already arriving at the Gulf and a new Platts Marker price shows them being priced against LLS. Today we look at the Eagle Ford marker price and what it means for the status of LLS versus WTI.
