- A shortage of takeaway capacity has created a scenario of “Haves” and “Have Nots” within oil producers and oilfield service providers.
- We believe the takeaway constraint is a relatively short-term issue that does not diminish the long-term attractiveness of the Permian Basin.
- For many companies impacted, a near-term hit to cash flows from wider price differentials and reduced production growth has only a small impact to long-term DCF valuations.
- We view the recent negative stock performance of many Permian-focused E&Ps and service companies as overly severe and particularly short sighted.
The famous criminal Willie Sutton is most known for his answer to a question of why he robs banks, “Because that’s where the money is.” In today’s energy sector, a similar answer could be given relating to oil producers’ attraction to the Permian Basin in West Texas and Southeast New Mexico. They have been drawn to the area for its rich oil reserves, multi-zone production opportunities, vast geographic size, relatively favorable regulatory environment, and the ability to piece together acreage to drill long laterals leading to high well efficiencies. For these reasons, the Permian has been the primary source of growth in US oil production since the shale revolution began roughly a decade ago.
Nevertheless, a critical near-term constraint has developed in the form of takeaway capacity (aka pipes to transport crude to the Gulf Coast or other key hubs like Cushing, OK). The lack of such infrastructure means that the Permian’s ability to move oil through pipes may fall short of expected production by 300,000 – 400,000 barrels per day by the end of this year and undershoot theoretical production by as much as 750,000 barrels by late 2019. Given the improbability for such a large amount to be transported by rail or truck, this would result in a significant amount of oil that is “stranded” in-basin.
As a logical consequence, a significant price discount for Midland (i.e., Permian) crude versus that priced at Cushing has recently developed, as well as an even larger discount to the waterborne price at the US Gulf Coast. As shown in the chart below, the Midland-Cushing price differential has fallen from a range of +$2/bbl to ($2)/bbl in recent years to a range of $(6)/bbl to $(12)/bbl over the past few months. Moreover, many analysts expect the discount to remain wide, given a prolonged shortage of pipes and the high costs to move oil by other means (estimated $12/bbl to the Gulf Coast by rail and $15+/bbl by truck).
The takeaway issue and resulting blow-out in price differentials has created a scenario of “Haves” and “Have Nots” within US oil producers and oilfield service providers. For producers, the “Haves” are those who have largely hedged their oil production (granted, many have hedged ’18 production, but few hedges for ’19 currently exist) or those who have secured Firm Transport (FT) on major existing pipelines leaving the Permian. In the latter case, producers are able to realize the price at the point of delivery, minus the transport cost (typically $2/bbl to $4/bbl via pipeline). Separately, for many service companies, the concern is that the lower in-basin oil price will reduce well completion activity (e.g., pressure pumping), lowering the rates they receive for their services. This also would likely negatively impact producers of completion-related equipment.
Meaningful relief to the Permian takeaway issue should come in the 2H 2019, when midstream companies have planned for the start-up of key long-haul pipelines, such as EPIC (2H 2019), Gray Oak (late 2019), and Cactus II (early 2020). At that point, we would expect in-basin price differentials to more resemble historic levels.
To us, the recent negative stock performance of many Permian-focused E&Ps and service companies seems overly severe and particularly short sighted. Counter to the current negative sentiment toward such equities, we would make the following points supporting investments in companies with large exposure to the Permian:
1. The takeaway constraint is a relatively short-term issue that does not diminish the long-term attractiveness and potential of the Permian Basin. As previously mentioned, we believe the Permian’s chocolate layer cake-like, multi-zone geology (“stacked pay”) positions it as the primary driver for US oil production growth. It is this structure that provides for the vastness of reserves for many Permian producers, as well as the well efficiencies through production techniques like cube development (simultaneously fracturing multiple wells to optimize ultimate recovery) and multi-well pad drilling. With such an abundance of reserves, the Permian has often been referred to as the “Saudi Arabia of US oil basins,” an analogy that we believe is well supported.
2. A decrease in near-term cash flows from lower in-basin prices and reduced production growth rates should have only a small impact on DCF valuations for most companies impacted. Although companies without established FT on existing pipelines will likely experience a hit to near-term cash flow, the value of their unaffected outer years cash flows should still represent the bulk of their firm value.
To illustrate this, we assessed the impact to a typical E&P discounted cash flow (DCF) valuation by creating a hypothetical high growth, oil-weighted producer. We kept all model assumptions constant (benchmark pricing, well costs, decline rates, operating expenses, oil cut, etc.), but modified estimated production growth and price differentials in our constrained case. In the constrained case, we assumed the price differential remains wide at $12/bbl and production growth is cutback by 10% in years 1 and 2, but this production growth is recovered by year 5 with higher growth in years 3 and 4 once the basin is debottlenecked. Thus, total production reaches approximately the same level in year 5 under both the constrained and unconstrained case. As a result of the production growth cuts (a slowdown in rig additions and/or deferred well completions) and wider differentials in the initial years, the value of our hypothetical E&P declines by less than 10%, with only 5% of the value of the firm represented by years 1 and 2 in the constrained case and 8% for the unconstrained scenario. The market caps for many exposed Permian-based E&Ps have declined by substantially more than this, which could indicate that the market is discounting a scenario that these bottlenecked barrels are not offset by increased drilling activity in later years.
As we have discussed, there are ample pipeline projects that should serve to debottleneck the Permian’s growth potential by 2020 which we believe should allow these companies to make up lost production growth. As such, in several cases, investors may be overly penalizing producers that still have the opportunity for significant growth in the future.
3. Completions will continue and are at worst deferred. We note that takeaway constraints could limit Permian production growth, instead of resulting in a decline from current levels. Therefore, onshore service companies, many of which have only recently regained margins reflective of healthy oil markets, would seem at risk of simply lower short-term earnings growth, rather than actual declines from current profit levels. This is particularly the case for companies less exposed to “tip of the spear” spot pricing. Also, complemented by the growing number of DUC (drilled but uncompleted) wells in the Permian, we expect the backlog of completion work to substantially tighten the service market, possibly boosting pricing, once the takeaway issue is alleviated.
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