Opinion

‘Permania’ prevails, and other learnings from the 2017 DUG Permian Conference

Jon Weintraub

Research Analyst, Lower 48 Upstream Oil and Gas

Jon works on reviewing trends and activities throughout the Permian basin.

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While many critical themes were hotly debated and actively addressed at the 2017 DUG Permian Conference, the general consensus amongst participants is the Permian’s ability to not only drive value in a sub-$50/bbl world, but to accelerate production growth in a range-bound price environment. Three main themes stood out:

(1) Companies have shifted to aggressive growth strategies, but are they sustainable?

(2) Will productivity be greater than cost inflation?

(3) How big can the Permian get?

Production growth is back, but at what cost?

After an active M&A market over the last 18 months, we are seeing a shift in operator mentality from acquisition mode to full-scale development. While we expected to see E&Ps highlighting aggressive production growth plans out to 2025, unintended consequences could be a lingering concern for those not investing towards long-term infrastructure and midstream capabilities.

While gas takeaway capacity in the Midland Basin is robust, lower oil cuts and a fragmented gas pipeline network in the southern and western portions of the Delaware Basin could be destructive in the short term. Water management strategy is becoming an increasingly critical consideration for many operators in the Permian, where water cuts are higher than other tight oil plays.

On average, trucking disposal water to third-party systems ($6.00/bbl) is considerably more expensive than piping to them ($0.40/bbl). Approach Resources has driven down its LOE cost structure from $7.36/boe (Q1 2014) to $3.40/boe (Q4 2016) by investing in its own water and centralized gas lift systems. Matador Resources plans to save approximately $200,000 per well by investing in its own water recycling system versus sourcing 100% freshwater and trucking saltwater disposals.

All quiet on the cost inflation front?

To our surprise, there was little mention of rising costs in 2017/2018. We believe a functioning and healthy service sector will be paramount in scaling up development activity. While we expect to see moderate cost inflation in 2017, underpinned by double-digit increases in pressure pumping, operators were quick to pivot our attention to continued improvements in productivity. Throughout the two days, there was lively discussion on the continuous and evolving “completion well design recipe”:

  • Ingredient #1 — Proppant loading: We noticed a gradual shift across the board in scaling down proppant loading. WPX Energy and Approach Resources highlighted diminishing returns on proppant intensity beyond ~2,500 lbs/ft. Noble Energy was the exception, pushing average proppant loading to 3,000 lbs/ft and completing tests at ~5,000 lbs/ft.
  • Ingredient #2 — Cluster spacing: Tighter cluster spacing and more frac stages are two catalysts that many operators see moving the needle on productivity gains in 2017. Operators are scaling down proppant intensity and redirecting attention to improved wellbore stimulation by increasing the number of fracs and shortening frac lengths. Previously, operators had been targeting fracture half-lengths of approximately ~500 ft around the wellbore. Now operators are aiming for half-lengths of ~300 ft with shorter distances between fracs.
  • Ingredient #3 — Lateral lengths: The Midland Basin has progressively seen operators targeting “super-laterals” going beyond 10,000 ft. Laredo Petroleum highlighted laterals over 15,000 ft. Conversations signal that we are in the later innings of optimizing lateral length, and some operators are starting to pull back. The Delaware Basin lags the Midland in terms of lateral lengths with several operators commenting that 7,500-ft laterals are the “sweet spot.”

Sky’s the limit: how far can acreage valuations, spacing assumptions and type curves go?

On several occasions, we heard some rather ambitious forecasts from various speakers. In some instances, we heard whispers of acreage projections going as high as $175,000 to $200,000 per acre. We also saw operators pushing aggressive downspacing assumptions with potential for 60 to 70 wells per section. In our view, this is not attainable unless operators can (1) sufficiently de-risk and prove commerciality in multiple stacked intervals at tighter well spacing, (2) exhaust all engineered locations in a short time frame (two or three years), and (3) maintain costs at Q4 2016 pricing levels. While we remain highly skeptical that all such obstacles can be overcome simultaneously, it certainly does play into the excitement of Permania.