WoodMac: SCOOP Core 'On Par' with Eagle Ford, Bakken Plays

WoodMac: SCOOP Core 'On Par' with Eagle Ford, Bakken Plays
Although the South-Central Oklahoma Oil Province (SCOOP) region will see setbacks, Wood Mackenzie analysts "expect it to bounce back quickly in 2016," according to its latest key play analysis.

Even in the current price environment, the best producing parts of the South-Central Oklahoma Oil Province (SCOOP) are on par with the Eagle Ford and Bakken according to Wood Mackenzie’s latest key play analysis.

"The region will see drawbacks, rig counts are down in the near-term but production won’t fall off by much and we expect it to bounce back quickly in 2016," said Brandon Mikael, Analyst US Lower 48 Upstream. "It's still one of the most exciting growth areas in the Lower 48 because of the stacked pay potential."

Wood Mackenzie's analysis breaks the SCOOP, STACK, and Cana Woodford plays down into nine sub-play areas that span the Anadarko and Ardmore Basins of the Mid-Continent.

"The area has some of the largest producing wells in the Lower 48, bigger than the Permian and Bakken and comparable to the best parts of the Eagle Ford," explained Mikael.

Currently, oil breakevens are lowest in the SCOOP Core where Springer and Woodford wells breakeven at WTI prices of $41/bbl and $47/bbl at our long-term Henry Hub price assumption of $4.12/mcf.

The key findings of Wood Mackenzie’s granular analysis of nine sub-play areas of the SCOOP are as follows:

  • Springer Shale – the best economics but limited running room: The $41/bbl WTI breakeven for the SCOOP Core Springer sub-play is lower than the Bakken Parshall Sanish and Eagle Ford Karnes Trough sub-plays (widely regarded as the best parts of those plays) which breakeven at $45/bbl and $48/bbl, respectively.
  • Upstream capital expenditure expected to surpass $4 billion in 2015: While operators will experience near-term relief in drilling and completion costs in response to lower commodity prices, the benefits are somewhat mitigated by an increasing concentration of activity in core areas where well costs trend higher due to deeper wells and longer lateral lengths.
  • Horizontal rig count: Horizontal rig count is expected to average 60 rigs in 2015. We expect a pullback from 2014's peak of 92 rigs as operators pivot from delineating unproven areas to focusing on drilling to hold core acreage.
  • Economics in non-core sub-plays are challenged at current prices: Type wells in four sub-plays are not NPV10 positive under our current base price deck (2015 WTI and Henry Hub prices of $55/bbl and $3.40/mcf) due to challenging, heterogeneous geology that contributes to the inferior well productivity relative to the best parts of the play.
  • Production to surpass 1 million boe/d by 2020: Production is expected to surpass 1 million barrels of oil equivalent per day by 2020 as well as become more weighted towards oil as SCOOP and STACK development outpaces Cana Woodford. While crude and condensate makes up 22 percent of the overall production mix in 2015, we expect this to grow to 26 percent by 2020


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