AFPM President Drenva presented this speech to XYZ group on X date:

 

Charlie’s usual intro that outlines the issue including regional problems like the East Coast  •    Domestic crude production has increased 3 million barrels per day in the last four years.  The US is now producing 8 million barrels per day of crude oil.  •    The new production has provided low cost feedstocks that have benefitted domestic refiners.  However, it has also created challenges.  •    Infrastructure limitations pose challenges in transporting this new crude to domestic refiners and to date have been the main reason why we have seen such large discounts in the inland domestic crude oil prices – not refiners’ “inability” to process to the crude oil: o    May 19, 2012 Reuters reports on the Seaway pipeline reversal: As the reversal began, “The spread between U.S. benchmark West Texas Intermediate and global benchmark Brent, similar crudes historically priced at or near parity, narrowed to $15 from almost $19 Wednesday.  It was as much as $28 late last year.”  o    Mar 18, 2014 Bloomberg reported on the Seaway Expansion: “West Texas Intermediate crude rose the most in two weeks, narrowing its discount ot Brent, after Enterprise Products Partner LP said it would more than double the capacity of its Seaway pipeline as early as May.”  One quote in the article said “this story clearly explains why WTI is firmer than Brent.  Seaway expansion will draw more crude away from Cushing.” o    EIA had several articles –      Dec 5, 2011 Today in Energy: “Spread between WTI and Brent prices narrows on signs of easing transportation constraints;      February 29, 2012, Today in Energy – “On February 10, the discount for Bakken crude oil reached a record $28 per barrel compared to WTI (see chart below). While this difference has narrowed recently, it was still at $13 per barrel as of February 22, which is high compared to historical levels. It is likely that concerns regarding oil transportation bottlenecks throughout the central United States and increasing production from shale formations in the northern United States are driving these price trends.”      June 28, 2013, Today in Energy: The narrowing of the spread is supported by several factors that have:  a) Lowered Brent (North Sea) prices because Brent-quality crude imports into North America have been displaced by increased U.S. light sweet crude production, reducing Brent-quality crude demand, and b) raised WTI (Cushing, Oklahoma) prices because the infrastructure limitations that had lowered WTI prices are lessening o    Even the swings in LLS relative to Brent have reflected much of the congestion that has moved from the Cushing area to the Houston and Gulf Coast areas.       Jones Act tankers to move this growing volume of crude oil have been in short supply.  Reuters reported the US Jones Act tanker rate hit a record of $110,000/day in December 2013.    •    Some articles/reports focus on the fact that, after years of “heavying up,” many refiners are now faced with a flood of light crude oil from the Bakken, Eagle Ford and other areas.  The complexity of refinery configurations means facilities cannot simply flip a switch and swap out all their heavy crude inputs with light crude oil.  But this has been misunderstood.    •    Contrary to some articles that claim “refiners cannot use the new light crude oil” or “refiners are no longer able to use more light crude oil” – they can.  Refiners that use heavy crude oil also use light crude oil, and they can increase their use of domesitic light crude oil.  They have been using increasing quantities of US light crude oil  and are not “maxed out” on their ability to use more crude oil.  Generally the steps they take are as follows:  o    Backing out imports of light crude oils, and using Canadian and domestic light crudes in their place.   o    Use any “unused” light sweet capacity  o    Back down intermediate crudes (especially sweet) to use more light sweet  o    If light-heavy price differentials are small enough, back down heavier crude oils, reducing use of coking unit to use more light o    Invest in changes to use more   •    Looking ahead, and assuming access to the crude oil continues to improve, Turner Mason (TMC) has made some estimates as part of their “North American Crude and Condensate Outlook.”  o    TMC estimated that, with limited further investments, mainly just improved access to this crude oil, refiners might be able to increase crude processing capacity by an additional 400 KB/D just by improving utilization rates.   o    When we include announced investments (for condensate splitters, capacity  expansions, etc.) , an additional 500 KB/D might be able to be processed if economics continue to favor this processing,  o    This brings us to a total potential increase of 900 KB/D (sum of the two).  It should be pointed out that this total is in addition the further displacement of waterborne imports (not only light, but also medium grades) which U.S. refiners will continue to do given advantaged domestic crude pricing. o    We still have some room to back down light crude imports, but exactly how much is not known, since much remaining imported volume (54%) is from Saudi Arabia:     This past March 2014, the US imported almost 622 KB/D of non-Canadian crude oil with API gravity 33.5 and higher.  While Bakken is about 38 API, Nigerian can be lower and it is one of the crudes being pushed out.       This compares to March 2007, when we imported 1260 KB/D of 33.5 and higher non-Canadian crude (about twice as much as this past March). o       •    (ONLY SAY IF ASKED..)  It isn’t clear when we might reach the point where production could exceed our capability because of a number of unknown factors. For example, production levels are key and we still see a lot of uncertainty in what they will be. Also, some crude imports are tied to joint ventures between crude producers and US refiners.  Those imports may not get backed out of the US, which leaves less room for US-produced crude oils.  We should have time to understand the full impacts of opening the export door.  (At least a year if not 2…)   •    [EXPORTS – Charlie, pretty sure you are good on the basics this topic (e.g. look at holistically, Jones Act, etc.  The following points get into the condensate issues a little more.]  •    Getting into more detail on crude exports, there is talk that the Administration may look to allow the export of condensates.  As you know, “plant” condensates – things like pentanes that are taken out of natural gas at a processing plant – can currently be exported.  But “lease” condensates, which are taken from the well head, cannot be exported.   •    US lease condensate is now at about 1.2 million barrels per day and expected to reach 1.6 million barrels per day by 2018.  Eagle Ford is the biggest production area for condensate.  Estimates indicate about 45 percent of the production there can be classified as condensates.  These estimates are from RBN Energy.  •    Right now, not a lot of refiners want this stuff for several reasons (capacity, quality, etc.), which means it is a buyer’s market and condensates have sold at a discount of $20/bbl compared to Louisiana Light Sweet crude oil.  (In Asia, condensate prices are close to LLS.)    •    Petchem manufacturers also have several options for condensates due to the shale boom, enhancing the buyer’s market phenomenon.  •    However, as previously mentioned, the condensate glut generated investment in splitters, which will increase domestic demand for lighter crudes.  •    This also raises questions about the implications of reclassifying condensates in a manner that allows them to be exported for refiners.  •    First, it is a complex political issue that would likely take time to ferret out.  But exporting condensates has fewer issues for refiners.    •    The world really wants condensates more than does the US.   o    Condensates in the US can be used for diluents with heavy Canadian crude oil, they can be fed to splitters attached to refineries where the refineries can use the heavier part of the condensates after removing the lighter naphtha materials, etc.  But the US has plenty of naphtha.  The US petrochemical complex is set up to use ethane as a primary feedstock in producing ethylene, unlike many other parts of the world where naphtha is the major petchem feedstock.    o    Other parts of the world still need condensates to get naphtha for petchem feedstock, material for gasoline belndstock, and material for refining distillate fuels.  This fact is highlighted by the fact that Asia continues to expand slitting capacity – with the Asia Pacific region showing splitting capacity increasing almost 550,000 B/D or over 50% from 2012 to 2017 (Asia Pacific Energy Consulting).   o    Condensate supply from the Middle East is not expected to keep up with the new demand.   If the US export ban on “condensate” is lifted, that product will go to where it can be processed most economically, and the Asian market is a likely candidate.  o    Just note that there is a market in the US for condensates; albeit not like that in other parts of the world.  The US has a few companies building and planning for splitters.  They are well aware of the potential for condensate exports, and have taken that into consideration.   CONCLUSION •    In short, between political issues, domestic investments and market dynamics, domestic refining capacity is a long way from being “maxed out” on light crude oil.  We have some time to get our hands around the regional issues that need to be understood before just opening the door.   o    Condensate exports should not be a major problem, and might provide even more time to make sure we don’t suffer any major unintended consequences .

AFPM Communications

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