More than a dozen crude oil pipelines can deliver up to 3.4 million barrels/day (MMb/d) to the greater Houston area, with another 550 Mb/d of capacity planned, and as domestic production starts to grow again, a new round of projects is under way to build-out the region’s distribution pipelines, storage and marine-dock infrastructure. The developers of these Houston-area projects include a range of midstream players: from large, diversified midstreamers that own the long-distance pipelines flowing into the region to smaller players planning their first Houston projects. Today we conclude a two-part blog series on the latest round of projects and on the increasingly intense competition for barrels.
Posts from Sandy Fielden
As U.S. crude production ramps back up and larger volumes flow to the Gulf Coast, competition is building among midstream companies for control over the final miles from pipeline to refinery or marine dock. Nowhere is this more evident than the Houston area, where more than a dozen pipelines can deliver as much as 4 million barrels/day to the region’s 10 refineries as well as to export docks. Owners of the long-distance incoming pipelines—seeking to secure terminal, storage and dock fees—are making significant midstream investment in Houston, but smaller players are also developing assets. Today we begin a two-part series describing the build-out and how competitive the market has become.
The five refineries in the U.S. Pacific Northwest (PNW) performed better in 2016 than rivals on the East Coast for two main reasons. First, the changing pattern of North American crude supply has worked to their advantage. Faced with the threat of dwindling mainstay crude supplies from Alaska, refiners in Washington State replaced 22% of their slate with North Dakota Bakken crude moved in by rail. They have also enjoyed advantaged access to discounted crude supplies from Western Canada. Second, PNW refiners face less competition for refined product customers than rivals on the East and Gulf coasts, meaning they have a captive market that often translates to higher margins. Today we review performance and prospects for PNW refineries.
The shale boom breathed new life into East Coast refineries that were under threat of closure by their owners between 2009 and 2012. Now some of those same refineries are under threat again, this time due to poor margins as well as the high cost of compliance with environmental regulations. After enjoying three years of improved margins through access to advantaged domestic crude delivered by rail from North Dakota, five East Coast refineries are now paying international prices for imported crude again in 2016 after differentials between domestic benchmark WTI and international equivalent Brent narrowed to less than $1/bbl in the wake of the crude price crash and an end to the federal ban on most crude exports. Today we discuss PADD 1 refinery prospects.
Two new 50-Mb/d, Kinder Morgan-owned and -operated condensate splitters came online during the first seven months of 2015, backed by a 10-year BP commitment to process a total of 84 Mb/d through the units. Located in the Houston Ship Channel’s refinery row, the splitters were expected to provide a profitable outlet to process growing volumes of the ultra-light crude oil known as condensate. Instead, average plant throughput through July 2016 has been only 71% of capacity, well below the 90% average operating level of neighboring refineries. The relatively low level at which these units have been operating reflects sagging condensate processing margins. Today, we detail how Kinder Morgan’s new splitters have been run during their first year or so of operation.
With crude storage tanks along the U.S Gulf Coast nearly full, the nine storage terminals currently operational in the Caribbean offer an advantageous close-by alternative. Right now these terminals are heavily used by Venezuela for oil blending and distribution, but there has been growing interest and investment from outside the region. China is now neck and neck with the U.S. as the world’s largest crude importer and is making a significant strategic investment in Caribbean storage to cement crude supply deals with Latin American producers. Private equity fund ArcLight Capital and trader Freepoint Commodities together purchased a huge terminal and shuttered refinery in the U.S. Virgin Islands in January of this year (2016) and have leased most of the working storage to Chinese-owned Sinopec. Today, we examine the growing role of Caribbean crude terminals. (This blog is based on Morningstar’s recently published Caribbean Crude Storage Outlook , which provides a comprehensive analysis of this evolving market.)
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.
A year ago (April 2015) the price spread between Light Louisiana Sweet (LLS) the St. James, LA benchmark light crude and Permian West Texas Intermediate (WTI) delivered to Houston was roughly $2.50/Bbl. In the first quarter of 2016 – following the end of the crude export ban and the crash of crude prices below $40.bbl – that spread narrowed to 30 cents/Bbl. This price differential change has thrown a wrench into traditional Gulf Coast price relationships that encouraged the flow of crude east from Houston to Louisiana. Further changes are expected as pipeline projects due to be completed in the next two years will deliver Bakken and Permian crude direct to St. James. Today we wrap up our series on St. James with a look at changing crude prices and flows.
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.
Two midstream operators have added at least 13 MMBbl of crude storage to the St. James hub during the past 8 years (NuStar and Plains All American). These companies have invested in the hub because of its proximity to the Gulf Coast and pipeline connectivity to refineries throughout the Eastern U.S. and as far northwest as Edmonton, Alberta. St. James has also been an active recipient of crude flowing east across the Gulf by barge and tanker from the Eagle Ford via Corpus Christi. These crude movements require terminal, storage and blending facilities. Today we describe crude storage facilities at St. James.
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.
The St. James, LA crude trading hub provides feedstock to 2.6 MMb/d of regional refining capacity as well as refineries in the Midwest. St. James is also an important distribution hub for crude from North Dakota, South Texas, the Gulf of Mexico and onshore Louisiana as well as imports arriving at the Louisiana Offshore Oil Port (LOOP). Crude storage and midstream infrastructure at St. James has been expanding in recent years as the trading hub handles larger volumes of domestic production. Today we begin a new series looking at infrastructure and crude pricing at St. James.
Although California refineries initially met the criteria that spurred development of crude-by-rail (CBR) shipments to other coastal regions (lack of pipeline infrastructure and wide crude price differentials between stranded inland supplies and coastal alternatives) neither rail shipments or terminal build outs have made much of a dent in the Golden States’ crude supply. At their height in December 2013 CBR shipments into California reached 36 Mb/d – just 2% of the State’s 1.9 MMb/d refining capacity and they have since dwindled to a trickle. Today we examine the low pace of shipments.
Most of the crude by rail (CBR) shipments to 4 refineries in Washington State are ex-North Dakota from where rail freight costs are over $10/Bbl. Bakken crude from North Dakota competes at Washington refineries with Alaska North Slope (ANS) shipped down from Valdez, AK. Back in 2012 ANS prices were more than $20/Bbl higher than Bakken crude – easily covering the rail cost. In 2016 so far the ANS premium to Bakken has averaged well below the $10/Bbl freight cost making CBR shipments uneconomic. But as we discuss today - Northwest refiners are still shipping significant volumes of crude from North Dakota.
In January 2016 the ICE futures Exchange changed the expiration calendar for its flagship Brent crude contract. The March 2016 contract expired on January 29, 2016 under new calendar rules that stipulate expiration one month and one day prior to delivery. This was done belatedly to reflect a change in the assessment of the physical Brent market that was implemented back in January 2012. On paper the change is just an overdue action by ICE to properly align the timing calendar for their popular futures contract with the underlying physical market. But in practice - as we suggest in today’s blog, the change has significant impacts on the calculation and analysis of the commonly utilized spread between ICE Brent (the international benchmark crude) and the U.S. equivalent West Texas Intermediate (WTI) crude futures contract traded on the CME/NYMEX.