Finding profitable markets for the rapidly increasing volumes of condensates produced in the Eagle Ford and other U.S. shale plays will be challenging. Sure there will be a growing Canadian need for condensates as a diluent for oil sands-derived bitumen, but that will still leave U.S condensate producers with a big surplus. The logical thing would be to look further afield, but selling to overseas markets— particularly to the growing Asia/Pacific region—is a complicated matter. First, an export license for “raw” (unprocessed) condensate to overseas markets is required, but no such licenses are being issued. Second, the Asia/Pacific region is also experiencing supply growth.
Daily Energy Blog
Thursday, 7/04/2013
Category:
Crude Oil
Tuesday, 7/02/2013
Category:
Crude Oil
Valero’s brand new $1.6 B, 60 Mb/d hydrocracker is set to ramp up at the company’s Norco, LA refinery this month (July 2013). They added a similar unit to their Port Arthur refinery last year and plan to expand existing units at their other refineries. Hydrocrackers leverage cheap US natural gas to boost production of ultra low sulfur middle distillates. That makes sense because of high diesel refining margins and a boom in exports over the past two years. But not many refiners appear to share Valero’s enthusiasm for these investments. Today we consider the benefit that these upgrading units offer.
Monday, 7/01/2013
Category:
Crude Oil
Permian crude production is expected to increase 28 percent between 2013 and December 2018 to 1.8 MMb/d (Bentek). Existing pipeline takeaway capacity and local crude consumption are currently barely enough to handle production of 1.4 MMb/d. However, planned new pipeline capacity should comfortably handle output by the end of 2015. Today we review the impact of new Permian takeaway capacity.
Sunday, 6/30/2013
Category:
Crude Oil
Permian crude production increased by 26 percent between January 2012 and May 2013 according to Bentek. Production is now about 1.4 MMb/d - virtually the same as existing pipeline takeaway capacity and local crude consumption. That tight balance has caused considerable price volatility between Midland, TX in the production region and Cushing, OK in the past year. Today we begin an updated analysis of Permian production and takeaway capacity.
Thursday, 6/27/2013
Category:
Natural Gas
NYMEX natural gas prices have fallen 16 percent since reaching their high for the year so far of $4.408/MMBtu on April 19, 2013. The NYMEX August contract closed at $3.582/MMBtu on June 27, 2013.The market is currently in the low demand shoulder season. Winter is over and summer heat is on the way but temperatures in May and June are not typically high enough to significantly increase demand for air conditioning. Today we review shoulder season gas market fundamentals.
Wednesday, 6/26/2013
Category:
Crude Oil
The new Turner Mason (TMC) study titled “North American Crude and Condensate Outlook” (NACCO) forecasts a high case 8.2 MMb/d increase in crude supplies from US and Canadian production over the next 10 years. While most crude imports will be pushed out by this production surge over the 10-year period, a minimum structural import level of about 1.4 MMb/d will remain. As domestic and Canadian crude supplies overwhelm refining capacity in coastal regions TMC predict crude exports will be required to balance demand. Today we review TMC’s crude market and refinery operations predictions.
Tuesday, 6/25/2013
Category:
Crude Oil
The volume of crude moving out of Corpus by barge and tanker increased from 7 Mb/d in January 2012 to 370 Mb/d in May 2013. At the same time two 300 Mb/d plus pipelines from the South Texas Eagle Ford to Houston are running at less than half full. We know these stats because of information from a company called Clipper Data, which among other things provides detailed waterborne movements of Eagle Ford crude from the Port of Corpus Christi to Gulf Coast destinations. Today we examine the shipping data for clues.
Monday, 6/24/2013
Category:
Refined Fuels
A couple of months back in March 2013, the US Environmental Protection Agency (EPA) released proposed Tier 3 gasoline regulations that, if approved, will go into effect on January 1, 2017. The new rules include lower sulfur specifications for gasoline and tighter emissions controls for motor vehicles. Tier 3 also encourages acceptance of higher percentages of ethanol in gasoline. These regulations come at a time when US refinery gasoline blenders are jumping through hoops to handle a flood of new light shale crudes and increased demand for natural gasoline exports to Canada. Today we examines the proposals and their impact on gasoline and natural gas liquids markets.
Sunday, 6/23/2013
Category:
Natural Gas Liquids
Two weeks ago we posted part 1 of a series looking to answer the question – ‘Are we likely to run into storage issues with NGLs in PADD 1 while we are waiting for infrastructure and demand side projects such as export terminals and petrochemical facilities to be built out?’ We assessed growing supply and demand mismatches, how production will move between regions, and set the stage for today’s blog where we will examine the need for and availability of NGL storage capacity in PADD 1. In today’s blog, we will finish painting the PADD 1 NGL storage picture.
Thursday, 6/20/2013
Category:
Natural Gas
Two years ago in June 2011 the forward curve for NYMEX natural gas pointed to $5/MMBtu for gas in 2012 – rising to $8/MMBtu by 2022. This week (June 2013) the forward curve structure looks much the same except that expected prices in 2022 are down two bucks at $6/MMBtu. In between those forward curves, spot prices for natural gas plunged to less than $2/MMBtu in April 2012 and climbed back up to $4/MMBtu a few weeks ago. Today we consder how changing production and new patterns of demand look set to change gas market price structures for good.
Wednesday, 6/19/2013
Category:
Petrochemicals
Emission regulations require that companies planning new olefin crackers in EPA designated nonattainment areas like Houston must buy emission credits prior to construction. The market for credits in Houston for one criteria pollutant – volatile organic compounds (VOCs) skyrocketed from $4.5K/ton in 2011 to $300K/ton this month. The scarcity of emission credits and their rising price threaten to constrain or delay new petrochemical plant builds and will continue to hamper plant development and expansions in the Gulf Coast region. Today we describe the challenge new projects face.
Tuesday, 6/18/2013
Category:
Petrochemicals
Cheap feedstocks resulting from dramatic increases in US shale production of natural gas and natural gas liquids (NGLs) have led petrochemical companies to plan at least 7 new processing plants - known as olefin crackers - all but one on the Gulf Coast. These plants are expensive (think $billions) and take years to permit and build. They also produce significant quantities of emissions that are restricted by the Clean Air Act (CAA) – some of which trade in a market that has been skyrocketing for the past few months – threatening to delay or constrain the Gulf Coast cracker building spree before it gets started. Today we describe the regulations.
Monday, 6/17/2013
Category:
Natural Gas
The natural gas trading market has been getting a lot of attention lately and not in a good way. A couple of weeks ago the Wall Street Journal published two articles describing the fact that traders have started to reduce their presence in natural gas storage. At about the same time, Oneok, once a big player in energy services shut down its operation that had used natural gas storage and pipeline transportation capacity to provide those services to the industry. With gas production still coming on strong, more gas being used for power generation and the possibility of serious LNG exports on the way, what’s the problem? Today we look deeper into turmoil in the natural gas markets.
Sunday, 6/16/2013
Category:
Crude Oil
According to a new study just released by Turner Mason titled “North American Crude and Condensate Outlook” (NACCO), U.S. crude oil production could nearly double between early 2012 and 2022. At least that is the Study’s “high case” production scenario. That is very good news for U.S. refiners. Perhaps less good is the fact that 80% of the volume growth is light sweet crude, super-light crude, or even lighter condensate. How will refiners digest all of this light crude and what impact will the growing supply have on price differentials? What will the surge of light crude mean for waterborne and Canadian heavy crude imports? Today we start a two-blog series that will examine some of the findings of TM&C’s “2013 North American Crude and Condensate Outlook” (NACCO).
Thursday, 6/13/2013
Category:
Crude Oil
Three years ago in June 2010, prices for the international benchmark Brent crude and the US domestic benchmark West Texas Intermediate (WTI) traded within $1/Bbl of each other. Then in August 2010, WTI began to trade at a discount to Brent that widened out as far as $28/Bbl in November 2011 and averaged $17.50/Bbl in 2012. Since May 2013 the WTI discount to Brent has narrowed to an average $8.50/Bbl. Today we wonder if it’s time to tie a yellow ribbon round a West Texas oak tree.
