Boom Clap – The Sound of My Netback? The Bakken Crude 2014 Roller Coaster
It’s
been a big year for oil production from the Bakken formation in North
Dakota with output passing the 1 MMb/d mark in April and expected to
close out 2014 at 1.25 MMb/d.
Crude netbacks (market price less
transport cost from the wellhead) suffered during the first half of the
year from narrowing coastal price differentials - denting the economics
of crude-by-rail - the most popular option to get Bakken crude to
market.
Rail freight costs look set to increase in 2015 with new tank
car regulations and requirements for wellhead treatment to remove
volatile components.
But those changes pale into insignificance compared
to the recent crude price nosedive. That threatens to reduce producer
revenues by billions of dollars in 2015 and puts the spotlight on higher
transport costs to get crude to market from North Dakota. Today we look
at the financial impact lower netbacks could have on Bakken producers.
RBN has tracked crude production and transportation trends in the
Bakken closely over the past three years - a period of rapid output
growth – up 270% from 343 Mb/d in January 2011 to 935 Mb/d in January of
2014 (data from the North Dakota Pipeline Authority - NDPA). During
that period of continuous growth, the greatest challenge for producers
has been finding markets for their crude and securing transportation to
deliver it competitively to refineries. That’s because North Dakota’s
small population consumes little oil and the state is located far from
large coastal refining centers.
As production took off in 2011, Midwest refinery demand for light
sweet Bakken crude was quickly saturated (many Midwest refineries are
configured to process heavier Canadian crude) leaving Bakken crude
supplies backed up on limited pipeline infrastructure and causing an
inventory glut at the Cushing, OK trading hub resulting in heavy price
discounting for Bakken crudes. During 2011 and 2012 the pipeline
congestion at Cushing combined with constrained pipeline take-away
capacity in the Bakken encouraged a build out of rail loading terminals
to deliver crude past the logjam and direct to coastal refineries (see
The Year of the Tank Car).
Railing Bakken crude to coastal refineries allowed the latter to take
advantage of competitive prices for domestic crude versus imported
alternatives (see
On The Rails Again).
Railroads appeared to be solving the North Dakota crude transport
challenge while producers waited for slower pipeline infrastructure to
be built out. And for East and West Coast markets where pipeline
infrastructure seems unlikely to get built because of geography (the
Rockies) or population density (East Coast) rail provided a “pipeline on
wheels” to get stranded crude to refineries.
But during 2014 a good deal of rain began to fall on the Bakken
crude-by-rail parade – first of all because of concerns about rail tank
car safety after several fiery accidents (see
The Trains They Are A Changin’)
that seem likely to constrain the volume of crude moved by rail in the
long run as well as raising freight and wellhead treatment costs. And
second because the economics of railing crude from North Dakota to
coastal markets took a hit from narrowing price differentials between
midcontinent crude benchmark West Texas Intermediate (WTI) priced at
Cushing, OK and coastal crudes such as Light Louisiana Sweet (LLS) at
the Gulf Coast and international crude Brent, which sets the market
price at the East Coast (see
I Can’t Stand The Train? and
Under Pressure).
When coastal crude prices were much higher than WTI it made sense to
pay higher rail freight costs to ship crude to those markets. As the
difference between WTI and coastal crudes narrowed, so did the incentive
to use rail transport.
On the plus side for Bakken producers there was
an expansion in outbound pipeline capacity from North Dakota to Cushing
and to the Gulf Coast during 2014. That new capacity encouraged
producers to get off the rails and to ship by pipeline. But although
moving Bakken crude to the Gulf Coast by pipe is typically less
expensive than railing it to East or West Coasts, crude delivered to the
Gulf from North Dakota struggled to compete with booming output from
the West Texas Permian and South Texas Eagle Ford basins.
Those shale
crudes have less distance to travel to the Gulf Coast so their freight
costs are lower. Bottom line – transport costs weigh heavier on North
Dakota producers – reducing their netbacks. Producers closer to market
usually make more money.
Nevertheless until the last few months of 2014 when the crude price
crash began to accelerate, Bakken producers could still expect
comfortable rates of return from crude prices at or close to $100/Bbl
even after swallowing higher transport costs. But the price crash in the
second half of 2014 (see
Crying Time at OPEC?)
pushed prices for WTI to as low as $55/Bbl by the end of December. If
prices remain at those levels for long then rates of return for many
North Dakota producers will fall to unacceptable levels with higher
transport costs making matters worse.
How much damage has the crude price crash done to North Dakota crude
producer’s revenues? We can’t know the real numbers yet, but to get an
idea of the kind of revenue destruction that lower crude prices bring we
ran the netback analysis we’ve used previously to determine the best
route to market for Bakken producers (see
On the Rails Again).
This analysis is illustrated by Figure #1 and details the netbacks that
North Dakota producers can expect from different routes to market and
transport choices.
Figure #1
Source: RBN Energy, Market data from
Morningstar (Click to Enlarge)
The map in Figure #1 shows North Dakota producer netbacks based on
prices for December 26, 2014. The various routes and modes of transport
from North Dakota to the West Coast, East Coast, Gulf Coast and Cushing,
OK are shown with different color lines.
In a minute we compare these
netbacks with the averages for 2013. First a more detailed explanation
of the netback analysis in Figure #1. Bakken producer netbacks are shown
along the top of the map and represent the crude market price at the
destination less the freight costs for each route as shown in the white
circles. These freight costs are based on a number of industry
presentations as well as published pipeline tariffs, terminal rates and
estimates of rail car leases. The cost estimates include all
transportation from the wellhead to the refining region and are by their
nature representative rather than actual. The yellow text boxes
indicate the market regional price in $/Bbl.
The numbers you see here
represent market pricing for December 26, 2014 when WTI at Cushing was
$55/Bbl, LLS at the Gulf Coast $57/Bbl, Brent (East Coast pricing) was
$59/Bbl and ANS (West Coast) was $58/Bbl. Looking at the boxes along the
top of the map, you can see that the highest netback is $46/Bbl and
that two routes have that netback – Cushing and the Gulf Coast by
pipeline. Next behind the two pipeline routes comes the Pacific North
West route with a $44/Bbl netback, followed by the Cushing, Gulf Coast
and East Coast rail routes – all with $40/Bbl. In summary – as of
December 26, Bakken producers could expect netbacks in the $40 - $46/Bbl
range with higher rail costs to the East Coast cutting that netback to
$40/Bbl. [Note producers that have hedging programs will be achieving
higher netbacks than these because their hedges compensate them in case
of lower market crude prices – but typical hedging programs only extend
out for 2015 so they will not be protected forever.]
How do these returns compare to previous netbacks for Bakken
producers? Table #1 shows both the results for December 26, 2014 and
average values calculated for the year 2013 on the same cost basis.
Along the top of the table are the different route options. Below are
two rows showing different netbacks. The first row is the arithmetic
mean of the market destination prices for 2013 less the same
representative freight costs used in Figure #1. The second row is a
summary of the results for December 26, 2014 shown in Figure #1.
Table #1
Source: RBN Energy (Click to Enlarge)
Row 1 in Table #1 shows that in 2013 as a whole, the Gulf Coast by
pipeline route provided the best netback for producers (green shaded
cell). Note that there was little available pipeline capacity to get to
the Gulf Coast during 2013 so most producers would not have achieved
that higher netback. You can see from row 1 in the table that rail
options to the West Coast, East Coast and Gulf Coast all produced
average netbacks over $90/Bbl during 2013. And if you compare rows 1 and
2 you see that the 2013 numbers are all double the recent values in row
2 - (except for Cushing by pipe that is under by a hair). This tells
us that the price crash has halved producers crude netback revenues
compared to 2013.
Next we made a guestimate of the total impact of the price crash for
Bakken producer netback revenue. In 2013, the NDPA reported North Dakota
crude production at roughly 314 MMBbl for the year. The average 2013
netback from row 1 in Table #1 is $91/Bbl meaning that North Dakota
netback revenue for the year would have been about (314 million * $91)
or $29 Billion. We then compared that number against 2014 production
volumes that we estimate should come out close to 399 MMBbl. First we
took an average of netbacks over 2014 (though December 26) calculated
the same way as for 2013 – about $83/Bbl – meaning that estimated 2014
netback revenue is 399 million * $83 or $33 Billion. In other words,
based on the netbacks, producers will get $4 Billion
more netback
revenue in 2014 than 2013 – not surprising given higher production and
high crude prices earlier in the year. Second we estimated what kind of
dent a full year at recent prices would have made to that $33 Billion
2014 expected revenue. To do this we multiplied 2014 expected production
of 399 MMBbl by the arithmetic mean of our December 26, 2014 netbacks
from Table #1 ($43/Bbl).
The result is 399 million * 43 or $17 Billion -
so here’s the sobering bottom line – North Dakota producer netback
revenue for 2014 would have been about $16 Billion lower at current
prices. So while we reiterate that this is ballpark math that $16
Billion sure represents a big hole in producer netback revenue and it
gives a pretty good idea of how much impact a 50 % drop in oil prices
has on producer revenues.
Certainly enough to cause careful
reconsideration of 2015 drilling budgets and close scrutiny of
production costs and break-even estimates for new wells. And in that
cost-conscious environment, higher transportation costs will weigh heavy
on rates of return - leaving the Bakken more vulnerable than other
basins closer to market.
In the next couple of weeks we will dig into more specific break-even
analysis for U.S. shale productions by region – including transport
costs estimates such as those we highlighted in this analysis.
