Securing exposure to Permian tight oil – Part 2
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We’ve argued why new entrants should buy into US tight oil. But the path into this rapidly expanding new resource theme is littered with banana skins. Due diligence squared is advisable. I asked Ryan Duman Principal Analyst US Lower 48 and Greig Aitken Head of M&A Research to play Devil’s Advocate for potential buyers.
First, oil price is critical. E&P companies need to build price resilience into future portfolios; and tight oil economics are very price sensitive. New entrants in search of growth should screen opportunities with great care.
US tight oil volumes are growing rapidly at present because operators are drilling the pick of the inventory, mainly prime, low break-even positions in the Permian’s Midland Wolfcamp and Delaware Wolfcamp plays. The Permian provides 3 million b/d of the 4 million b/d growth in US onshore oil over the next decade.
But these sweet spots won’t last forever. The best acreage in the Bakken and Eagle Ford is already largely drilled out, and break-evens rising accordingly.
The same will happen to the Permian in due course, likely in the early 2020s. A prolonged return to US$50/bbl Brent or below would wipe out the growth in volumes in most of the plays including the Permian, killing the profitable growth that new entrants seek.
Second, deal value. Superficial valuation metrics are soaring: Permian real estate was sold at under US$5,000/acre in 2012, whereas buyers routinely pay US$50,000/acre today. The rise reflects competition for assets; a willingness to bet on unproven multiple zones; and assumptions of falling unit costs and increased initial productivity.
Fundamental valuations in contrast have proven relatively stable. The ILTOP for multiple Permian deals over the last couple of years averages US$65/bbl, close to the average for conventional asset deals globally. This is our proprietorial metric - the Implied Long Term Oil Price (Brent) that gives a 10% IRR based on WoodMac’s cash flow model of the assets. Our models also make certain assumptions for unproven upside.
The art of the deal in tight oil therefore is to match or better the assumptions made in the acquisition price.
Deploying more rigs, tighter well spacing, faster exploitation, shared infrastructure, and uncovered logistical synergies can justify high acreage prices – indeed all of this has to be done. But if it doesn’t work, over priced real estate on the balance sheet gets written down and turned back into moose pasture.
Third, the unique risks of tight oil and operating in the Permian. Once the acreage is in hand, it’s not just about getting down to drilling. Operators need to adopt a holistic approach to exploiting the play, working a different business model many new entrants will not be used to.
Decisions which can determine value creation or destruction include getting the best rigs and crews that can drill and complete with the latest technology; using the supply chain cost effectively such as choosing whether to buy-in proppant from out-of-state or invest in a sand mine; targeting the best of the multiple benches in the reservoir; avoiding parent/child well pressure interference; managing the unknowns like true terminal decline rates; how to get the oil to market when the current lack of available pipeline capacity has caused local spot prices to plunge to big discounts to WTI at the Gulf Coast.
The returns generated from unconventional assets are a bone of contention. At US$50,000/acre, achieving acceptable returns will be very tough without perfect execution.
Certainly, incumbents hold all the aces in M&A. They can access contiguous acreage, leverage experience of the local supply chain and geology, high-grade drilling inventory at their own clip rather than how new leases dictate, and efficiently deploy capital and resources. The new entrant has none or very few of these advantages, and based on our analysis typically makes lower returns.