BY Andy Hill, John Mayes and John Auers
While activity in the Permian basin has been booming of late and even the Eagle Ford has shown strong signs of reversing the steep declines seen over the last 18 months, the Bakken has remained behind., A major disadvantage of the latter compared to its two main light tight oil (LTO) competitors is its remoteness to refining centers and tidewater. As a result, it has had to rely on high cost rail transportation to supplement limited pipeline takeaway capacity to access markets. In an effort to remedy this situation, Energy Transfer Partners (ETP) developed the Dakota Access Pipeline (DAPL), which would significantly increase pipeline capacity and together with another new pipeline project would allow much lower cost access to USGC refineries and export facilities. This project received strong shipper support and was well on its way to completion by the end of 2016, until protests organized by Native American groups, supported by environmentalists and other anti-oil entities, convinced the Obama Administration to put a halt to the project. Now, with a new industry-friendly administration in place, the hold on the project has been removed and completion of DAPL is imminent. But what impact will it have on Bakken production and crude markets? Will producers (and refiners) be channeling Ric Ocasek and belting out “Just What I Needed,” or will production in North Dakota continue to struggle compared to its LTO peers? We explore this subject in today’s blog.
What is DAPL?
The DAPL pipeline has been the most publicized piece of the energy industry over the past six months. The pipeline itself runs from Bakken producers in North Dakota to the Patoka market. The second leg of the DAPL startup is the ETCO pipeline, a converted natural gas line which will further move Bakken crude to the Houston refining market. The nearly 2,000 miles of pipe will completely restructure the market for Bakken crude oil. Current production in North Dakota (according to the EIA) is roughly 1 million BPD. This pipeline system will have a capacity to move 470 MBPD – nearly half the current production. Obviously, this creates a big step change in market dynamics by drastically increasing the outlet capacity for Bakken producers. Further, it also adjusts the dynamics for refiners that have relied on Bakken crude at distressed pricing, as well as USGC refiners that source light crude feedstocks.
Production in North Dakota has been on a rollercoaster in recent years. After peaking in December 2014 at slightly over 1.2 million BPD, output has fallen to a recent low of 944 MBPD in December of 2016. Higher prices have recently reversed this downward trend, but only slightly. The EIA estimates that production in January 2017 was slightly over 1.0 million BPD, but estimated output in the 1Q17 remains marginally under the 1.0 million BPD mark.
The North Dakota Pipeline Authority (NDPA) remains optimistic about future production rates. Depending on the pricing scenario, the NDPA sees output rising to between 1.45 million BPD and 1.8 million BPD by around 2030.
“Just What I Needed” – Supply Side Implications
Just a few years ago, the industry was high on the crude-by-rail phenomenon. Rail terminals were cheap and quick to construct (relative to pipeline capacity), and could leverage the existing railroad infrastructure to move crude. The rail phenomenon had its issues, and along with the dramatic drop in crude price, eventually died down. The Bakken field was the poster child for crude-by-rail due to severely limited pipeline connectivity. Bakken crude, a light sweet crude, was heavily discounted as it was stranded in the Midcontinent and dependent on the high cost of rail to move it out. At its peak, the Bakken field railed about 700 MBPD out, mostly to the USAC and USWC refineries. Today, that number is closer to 200-300 MBPD.
PADD I has seen the greatest reduction in Bakken receipts as a result of the higher relative prices brought on by declining production rates. PADD I refiners have returned to a larger diet of west African and other foreign light sweet grades as Bakken prices strengthened. Higher Bakken production rates in the future are likely to weaken Bakken prices (relative to other grades), which could again, switch PADD I back to processing larger volumes of Bakken.
Bakken spot-pricing is dependent on how its incremental production is handled. With the DAPL and ETCO pipeline system starting up, incremental production will move south to the USGC, rather than by rail to the USGC, USAC or USWC. This doesn’t mean that Bakken will dry up in the USAC and USWC refineries. Demand from those regions may stay put depending on take-or-pay arrangements or regional economics. The incremental production, or marginal production, will flow south, however. The tariff is expected to be approximately $7 per barrel from North Dakota through Patoka and into the Houston terminals. Rail transportation into the USGC is estimated at $12, an estimated $5 over pipeline. This indicates that as the pipeline starts shipments, Bakken pricing will increase to parity value in the USGC less shipping costs.
“I Needed Someone to Feed” – Refining Implications
Domestic consumption of Bakken crude should remain relatively unchanged as a result of the pipeline startup, but the distribution will change the market dynamics. USAC and USWC refineries will be increasingly reliant on light crude imports while the USGC will see its light crude choices increase. The Houston refineries already have access to Permian and Eagle Ford production, and will now add Bakken to the mix. The Bakken production will initially reduce light crude imports to structural minimum levels. Average import levels for 2016 were 3.4 million BPD total, 600 thousand of which were considered a light grade. Of the 600 MBPD light crude imports to the USGC last year, 490 MBPD were from the Middle East. This provides a level barely large enough to be replaced by a full DAPL pipeline. While that balance fits for the time being, forecasts are that as the crude price rises, more discretionary spending will push U.S. production levels higher. At that point, if you assume a full DAPL pipeline, the USGC has an excess of light crude and must either export light barrels, run higher throughputs of light barrels, or move them to other U.S. regions.
On a regional level, the USGC could push out 470 MBPD (pipeline capacity) of imports from the USGC. From a sub-regional level, the Houston market will be awash with light crude and will need to push more to the Corpus Christi (unlikely, should already be at max-Eagle Ford rates) or Louisiana refining centers. Out of the 600 MBPD light crude imports, only 325 MBPD were into Houston refineries. This will increase the importance of the East-West pipelines, such as the Zydeco pipeline (formerly Ho Ho pipeline, or Houston-to-Houma pipeline). If the Zydeco pipeline is full, light crude will have to move via water.
This analysis generally ignores any structural minimums that may apply to these markets. Saudi crude is the only light crude imported into this region in substantial quantities. Saudi Aramco has stake in the Port Arthur refinery over the long term, and may decide to source a minimum amount of Saudi Light despite regional economics and the excess supply of American light crude oil.
We will continue to watch the startup of DAPL and its impacts on pricing and refinery demand. We focus on these types of issues in our recently issued 2017 Crude and Refined Products Outlook (C&RPO). Included in our C&RPO is a detailed forecast of both crude and product prices for all the key regions worldwide. Pricing is based on a variety of factors, including pipeline availability, but also are impacted by other dynamics not discussed in this blog. Supply of refined products is also a key part of the equation, and we include an analysis and forecast of the impact of new refinery projects on the supply of gasoline and other products in the C&RPO. For more information on these reports or on any of our other analyses or consulting capabilities, please send us an email or give us a call.