Saudi's war against Yemeni rebels last week helped to boost oil prices but the lift was only temporary. As the Sunni/Shia conflicts in the Middle East play out we could see much higher prices. However, our more immediate fate is based on the war between the shale producers in the USA.
The various shale fields have different economics and producers with the majority of their rigs in the low cost fields will continue to produce and have marginal success while waiting for prices to rise. The producers in the high cost fields will continue to terminate rigs and reduce their drilling to the bare minimum required to fulfill their agreements and lock in leases with production.
The highest cost fields in order are Mississippi Lime, Granite Wash, Bakken and Permian. They should see the biggest decline in active rigs.
The next highest cost fields in order are Rockies, Fayetteville, Niobrara, Barnett, Eagle Ford and Marcellus. They are expected to see moderate reductions in rig counts.
The lowest cost fields in order are Woodford, Utica and Haynesville. I would expect to see very little reduction in rig counts from those fields.
Having that knowledge is only half the battle. You also need to know who is drilling in those specific fields. Since nearly everyone is in multiple fields it is difficult to specify what their actual exposure is but I will take my best shot.
Of the top 15 shale oil drillers Conoco is the least exposed to high cost fields. About 78% of their production comes from the middle to the low end of the cost curve. About 22% comes from the second group of highest cost fields listed above. This means Conoco is well insulated from the rig cuts and will probably slow drilling on only a small portion of their activity.
Southwestern Energy (SWN) is the next best positioned with 32% of their activity in the second tier group above. However, 68% of their activity is in the second highest cost group. They are primarily engaged in drilling for gas although they are trying to get more oily.
The most exposed companies should experience the largest decline in drilling activity. Those with activities in the highest cost fields are Apache (88%), Devon Energy (84%), Sandridge (70%), Exxon (65%), BHP Billiton (62%), and Continental Resources (51%). These should experience the largest declines in rig activity.
Those heavily involved in the second highest cost group of fields and their activity percentage include Marathon (97%), EOG (91%), Anadarko (88%), Noble Energy (76%), Whiting Petroleum (76%), Chesapeake (76%), Pioneer Natural (55%) and Continental (49%). They should all experience strong rig declines because they can't drill profitable wells in those fields at $50 oil.
Refiners are spending more and more money to get oil direct from the oil field rather than source it from a pipeline coming from Cushing Oklahoma. The reason is the bad oil coming from Cushing. I have mentioned many times that Cushing is the delivery point for crude oil futures from all over the country and Canada.
WTI or West Texas Intermediate is supposed to have an API gravity range between 38-40. That is a measure of how light the oil is. A higher number means it is lighter and a lower number means it is heavier. The crude oil from most of the shale fields is rated between 45 and 60 or even higher. It does not qualify as WTI over 40. That means it sells for a cheaper price. However, a majority of the pipelines end at Cushing. This ultra light shale oil is then blended with Canadian Select from the oil sands, which has a gravity of 20. The idea is to take the heavy oil and blend it with the ultra light oil and end up with a gravity of 38-40. However, it is easy to say but hard to do.
Because the oil flowing into Cushing comes from multiple wells and multiple fields the gravity changes daily based on the flow from each field. Mixing it perfectly with Canadian oil is more luck than science.
Refiners don't like the oil that Cushing produces. It is called dumbell crude. It produces products on the high end of the scale like gasoline and low value products like fuel oil and asphalt. Because Canadian crude is relatively clean the blended product does not produce high profit middle grade items like diesel that comes from regular WTI or in even greater quantities from heavy sour crude from places like Venezuela. Refiners want an oil product that produces all the refined products because that creates more profits per barrel.
In order to get around this problem refiners are buying tanker trucks and railroad cars so they can source their oil directly from the oil fields. Late last year Delek Partners paid $11.5 million to buy 200 trailers and 120 trucks to haul them. While this may seem like a lot of work to keep a truck fleet running from oil fields to your refinery they say it is worthwhile to be able to know what oil you are getting and how it will refine.
In 2013 truck deliveries to refineries rose to 400,000 bpd and twice the rate in 2010. The numbers for 2014 are not in yet but you can bet they increased significantly. Marathon Petroleum increased its truck fleet by 16% in 2014 to 170 tanker trucks. Western Refining is planning on increases its fleet to haul more than 50,000 bpd to plants in New Mexico and West Texas, up +39% from 2014.
Pipeline operators are catching on as well. Several have agreed to ship crude oil from various fields in different batches to Cushing rather than stream them all together as has been the normal practice. Pipelines forced to stream multiple types of ultra light crude are going to have to discount it to the refiners to make it worth their while to refine the oil. If the discount is high enough it can make up for the lack of high profit products on the output side of the refinery. Bakken crude sold for as little as $32 a barrel a couple weeks ago because it is ultra light crude and the transportation charges are expensive. This is another reason why the number of new Bakken wells is going to decline significantly. They are not getting $50 a barrel or even close.
Active drilling rigs declined -21 to 1,069 for the week ended on Friday. Oil rigs declined -12 for the week to 813. Active gas rigs fell -9 to 233 and a new 18 year low. Active rigs have now declined -883 since the high of 1,931 in September. That is a -45.7% drop. Active offshore rigs declined -3 to 34 and well off their February high of 54.
Crude inventories rose another 8.2 million barrels to 466.7 million and the highest level for March since 1931. Crude inventories have risen +84.2 million barrels over just the last 11 weeks. Inventories are 22% over year ago levels and 26% above the five-year average.
Refinery utilization rose to 89% last week from 88.1%. Imports declined from 7.5 mbpd to 7.39 mbpd. U.S. production rose +3,000 barrels to 9.422 mbpd and the highest level since 1972.
Cushing inventories rose +1.9 million barrels to 56.3 million and a 6-year high. Cushing is now at 80% of capacity at 56 million barrels and the level where inflows are curtailed in order to maintain operational capability.
EIA Crude Inventory Chart
Gasoline inventories declined -2.0 million barrels to 233.4 million. Gasoline demand fell -641,000 bpd and imports dropped -221,000 bpd.
Distillate inventories were flat at 125.8 million. Demand rose +192,000 bpd. Imports rose +122,000 bpd.
In the graphic below green represents a recent high and yellow a recent low.
Propane inventories rose by 75,000 barrels to 55.03 million. Demand was flat at 1.08 mbpd.
Natural gas inventories ROSE +12 Bcf to 1,479 bcf. Inventories are now -11.6% below the five year average of 1,673 Bcf and +63.6% above year ago levels at 904 Bcf.
The blue line in the chart below shows the current inventory relative to the five year average.
The market fell sharply last week with the Dow dropping more than -400 points. This week could start bullish as end of the quarter money is put to work by fund managers. The first two weeks of April are typically bullish then the "sell in May" worst six-months of the year strategy begins to take effect.
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