According to the Energy Information Administration (EIA), liquids production from the Utica shale in Ohio (identified as crude oil but more likely all lease condensate) has more than trebled since January 2014 from 19 Mb/d to a projected 64 Mb/d in May 2015. Regional production of plant condensate from natural gas processing has also increased with the build out of gas processing capacity in the Utica and nearby Marcellus plays and could reach 50 Mb/d by the end of 2015. Midstream companies have been busy developing infrastructure to get this condensate to market. Today we look at developing infrastructure and markets for Utica condensate.
Posts from Sandy Fielden
Data from our friends at Genscape indicates that an average 150 Mb/d of Bakken crude is being unloaded at the Plains All American and NuStar Energy partners rail terminals at St. James, LA. That is down from 250 Mb/d just two years ago (April 2013) but still represents a substantial target for pipeline developers to aim for. The first significant project to offer pipeline service from North Dakota to St. James is being developed by Energy Transfer and Phillips 66. Today we review the project details.
Data from the new Energy Information Administration (EIA) monthly report on crude-by-rail (CBR) shows a marked increase in shipments out of the Rockies during 2014 as production outstripped pipeline capacity. The data history EIA provides also shows that significant CBR movements within the Gulf Coast region (presumably out of the Permian) occurred in 2013 when crude price differentials helped rail economics. Rail shipments to California from Texas have yet to take off however. Today we wrap up our analysis of monthly EIA CBR data.
The major re-plumbing of the U.S. crude pipeline distribution network to get 4 MMb/d of new domestic production as well as incremental Canadian barrels delivered to refineries is getting close to completion. The price crash and an expected slow down in production will almost certainly slow the pace of infrastructure development. The result is likely to be intensified competition between rival midstream companies and industry consolidation. Today we look at the larger implications of a small pipeline project in Houston.
The flood of domestic light shale crude showing up at the Texas Gulf Coast by pipeline in the past two years is not best matched to most refineries in the region that are configured to run heavier crude. But flows across the Gulf Coast to refineries in the Mississippi Delta more suited to process light crude are constrained by a lack of pipeline capacity between Texas and Louisiana. New domestic shale crude has been delivered to eastern Gulf Coast terminals such as St. James by rail but narrowing coastal differentials to inland prices have reduced the CBR advantage. Today we detail how new pipeline projects promise to increase the flow of crude from Texas to the Eastern Gulf.
The Plains All American (PAA) Cactus Pipeline comes online in the West Texas Permian this month (April 2015). Cactus will bring up to 250 Mb/d of crude and condensate from Midland and McCamey in the Permian to Gardendale, TX - the heart of the Eagle Ford shale – linking the two basins for the first time by pipeline. It also forms a major component of an expanded pipeline and dock infrastructure owned by a combination of PAA and Enterprise Product Partners (EPD) set to deliver as much as 600 Mb/d of crude and condensate to Corpus Christi and 470 Mb/d to Houston by the end of 2015. Today we describe how a good deal of those deliveries will be processed condensate eligible for export.
Data from the new Energy Information Administration (EIA) monthly report on crude-by-rail (CBR) shows that shipments from Canada increased from less than 10 Mb/d two years ago in January 2012 to over 130 Mb/d in January 2015. The increase in CBR movements mirrors increasing Canadian crude exports to the U.S. – the majority of which are still pipeline movements. Today we look at the destination markets for Canadian CBR in the light of congested pipeline capacity out of Western Canada.
Data from the North Dakota Industrial Commission (NDIC) indicate that production in January 2015 slowed by 37 Mb/d from record levels over 1.2 MMb/d in December. The number of new well completions also slowed in January – leading to a large backlog of wells drilled and waiting to start producing. Lower production and completions are in part due to producer caution following the crude price crash last year but producers waiting for a North Dakota state tax break and the usual impact of winter weather could also be responsible. Today we describe how new state tax incentives could boost summer output back to record levels.
According to a new set of data released at the end of March by the Energy Information Administration (EIA), crude-by-rail (CBR) movements jumped from 20 Mb/d in January 2010 to almost 1 MMb/d by December 2014. The big increase in CBR shipments has coincided with a 71% increase in U.S. crude production and has successfully helped alleviate a number of pipeline transport constraints. While overall crude-by-rail volumes have grown in the past 5 years, favored origins and destinations have changed considerably as the midstream industry has successfully re-plumbed the pipeline network to handle new crude flows. Today we review the new EIA report data on rail.
RBN has documented many fundamental influences on crude oil prices including supply, demand and inventory levels as well as infrastructure constraints. One that we don’t often mention is the strength or weakness of the U.S. dollar. As with most international commodities - oil is bought and sold priced in U.S. dollars. As a result, a change in the value of the dollar relative to other currencies has an impact on oil prices. Likewise the dramatic fall in oil prices since June of 2014 has been mirrored by the dollar rising to levels not seen since 2003. Today we look at how oil prices are impacted by the value of the dollar.
In spite of a brief respite provided last week by increased geopolitical risk in Saudi Arabia, crude oil prices are still in the $50/Bbl range – down more than 50% since last Summer - and inventories at Cushing and on the Gulf Coast continue at record levels. The fall in crude prices was initially consistent across markets with international benchmark Brent trading within $1/Bbl of U.S. benchmark West Texas Intermediate (WTI) and Gulf Coast marker Light Louisiana Sweet (LLS) in January 2015. But since February the relationship between Brent, WTI and LLS has changed as the build up of Cushing inventories weighs on prices in the Midwest. Today we provide an update on crude price differentials at The Gulf Coast.
Ever since crude oil prices began their precipitous fall in June 2014 market watchers have picked through the tealeaves of every OPEC statement - particularly those of Saudi Arabia - for signs of a change in policy. One widely watched signal comes every month when the Saudi’s publish differentials that determine the price customers pay for their crudes. Today we explain how Saudi pricing formulas work.
Last year was a banner year for the sand mining companies that cater to the U.S. shale drilling services industry. That’s because in 2014 well operators significantly increased the amount of sand used to complete fracturing operations in shale plays – from an average of about 5 MMlb for a single well to 15 MMlb (7,500 tons) or more.
Newfield Exploration - the largest crude oil producer in Utah’s Uinta basin - has temporarily suspended new drilling operations there in response to lower prices. Other producers in the region have reduced their drilling and capex budgets as well. The cutbacks stem in part from the extra logistics expense required to deliver and process the thick yellow and black “waxy” Uinta crudes that do not flow at room temperature.
In the past 10 years Marcellus and Utica shale drilling has transformed the U.S. Northeast from a sleepy backwater of gas production into a powerhouse that (according to the Energy Information Administration) supplied 22% of total U.S. gas production in December 2014. NGL production from the region is already 8% of the U.S. total and likely headed toward 20% by 2020. These vast shale formations cover most of Pennsylvania, West Virginia and Eastern Ohio, but it turns out that most of the production comes from only 20 or so counties across those three states. Such geographic concentration has significant implications for regional infrastructure development and capacity. Today we describe where producers have found success in the region.