Diesel demand in the Permian Basin keeps growing as drilling for crude
intensifies, fueling not only the rigs, but the trucks moving frac sand
to the wellhead and crude from wellhead to refineries, pipelines and
storage tanks.

And, despite sharply higher ULSD prices, diesel demand is rising in
tandem with higher production, which feeds the global appetite for
price-advantaged Permian crude exports.

May Permian crude output is on track to reach 3.199 million b/d,
according to US Energy Information Administration estimates, with June’s
production expected to be 3.277 million b/d.

Current Permian pipeline takeaway capacity is 3.2 million b/d. And, even
assuming Energy Transfer Partners completes its previously announced
200,000 b/d expansion of Permian Express 2 later this year, it won’t keep

So as Permian takeaway pipeline capacity is surpassed by regional
production, trucks will become necessary to take up the slack, with the
cost of trucking becoming the “trend setting price differential,”
according to David Vernon, Bernstein’s North American transportation

Vernon, on Bernstein’s Tuesday Permian webinar, noted that while rail
capacity will be available to move some barrels, it will not be enough to
move the 800,000 b/d of crude production stranded before additional
pipeline capacity comes online in the second half of 2019.


Growing rig and truck demand for diesel has helped push the Gulf Coast
diesel differential to the NYMEX June ULSD futures contract minus 2.15
cents/gal on May 8, its highest point since Hurricane Harvey disrupted
the market in August 2017. Excluding the storm, it is the strongest the
market has been since October 2016.

While a variety of the forces, such as export and planting season demand,
have contributed to the strength, the market has risen along an increase
in the Texas rig count. There were 523 rigs operational in the week that
ended May 11, according to Baker Hughes. There were 501 operational in
the week that ended April 13 and 452 running in the week that ended
January 12. And a rule of thumb says each rig uses between 35 and 50
barrels of diesel a day.

“Rig counts are more important for overall health,” a ULSD source said.
“Drilling support is big driver of ‘local demand.'”

Sources said Monday there was a 15-to-25-point premium for Texas-origin
ULSD barrels over Colonial Pipeline barrels. Buyers traditionally have to
pay a premium for barrels that can be moved onto the Magellan or Explorer
pipelines, the former of which connects to El Paso.

“ULSD demand in North Dakota, Wyoming and also New Mexico and West Texas
has been increasing,” a second ULSD source said. “There is more trucking,
but it’s mostly more demand for the diesel engines used for the fracking
of wells. It’s a premium market that’s been pulling barrels from the US
Gulf Coast.”


Several infrastructure projects are now on the drawing board in response
to rising ULSD demand in West Texas and New Mexico.

Magellan Midstream Partners extended an open season for expanding
capacity on the western leg of its refined products pipeline in Texas
before announcing Monday it would raise its capacity by 50,000 b/d to
150,000 b/d by mid-2020.

Connectivity to ExxonMobil Pipeline Co.’s terminal in Wink, Texas, will
also be added as part of the expansion.

Magellan said that due to strong shipper interest it will conduct
another, supplementary open season to gauge demand for boosting the
pipeline’s capacity to 170,000 b/d and construction of a new refined
products terminal in Midland, Texas, is under consideration.

Holly Energy Partners announced in April the intention to build a truck
rack in Orla, Texas, capable of providing the market with 30,000 b/d of
diesel. The facility will be connected to the company’s refined product
system in Texas and New Mexico.

“This asset will serve growing diesel demand associated with oil patch
activity in and around the Delaware Basin,” George Damiris, CEO of both
refiner HollyFrontier and its MLP Holly Energy Partners, said during a
May 1 first-quarter 2018 earnings call.


Trucks are likely to trump rail transportation because the “spread is not
wide enough for rail,” said Bernstein’s Vernon, adding railroads want
some assurance that spreads will remain wide before they commit to
putting “iron to ground,” having learned lessons from the sharp drop off
in railed Bakken crude following the 2015 peak.

Rail costs are about $7/b to $8/b from the Permian to the “tidewater” of
the USGC, Vernon said, but crude competes with frac sand for rail space.

Union Pacific, which has a large Permian rail footprint, said Q1 sand
carloads rose 52% year on year, while petroleum carloads increased 22%
compared with Q1 2017, volumes driven primarily by crude shipments. So
far in 2018, petroleum volumes, which include crude and LPGs, are up 24%
year on year.

While US Atlantic Coast refiner PBF mulls the possibility of railing
Permian crude to its Delaware City, Delaware, rail yard, Vernon said USAC
refiners were more likely to move crude by water from the USGC.

Jones Act tanker rates are $6/b between the USGC and USAC, while rail
costs from the Permian are about $10/b, sources say. Per barrel truck
costs are higher, at about $12/b, according to Phillips 66’s

However, overall Permian crude transportation costs could rise more as
more trucks take to the road, squeezing an already tight labor market and
raising salaries. The Dallas Federal Reserve noted the Permian’s
unemployment rate fell to 2.7% in March from 2.8% in February.

Additional trucks would add congestion to increasingly busy roads,
lengthening travel time.

Noting a typical truck can haul about 180 barrels of crude, Jeff Dietert,
Phillips 66’s head of investor relations, said it means 100 trucks are
needed to move 10,000 b/d.

“It’s not really realistic to expect to move 100,000 b/d or 200,000 b/d.
It’s just not really practical,” Dietert added.

–Janet McGurty in New York, janet.mcgurty@spglobal.com, with Allen Reed in
–Edited by Keiron Greenhalgh, newsdesk@spglobal.com

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