Beating the Best: Eight Characteristics of Winners in the Shale Arena

Beating the Best: Eight Characteristics of Winners in the Shale Arena

          
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Beating the Best: Eight Characteristics of Winners in the Shale Arena

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  • Separating the Best from the Rest

    Over the past three years, The Boston Consulting Group has developed an Unconventional Performance Database comprising operational and financial data for many companies operating in North American shale basins. (See “Tracking the Performance of Companies Operating in North American Shale Basins.”) The database was designed to offer an outside-in view of basin characteristics and operators’ results and to provide insight into what drives company performance. Unlike many outside-in benchmarking studies, BCG’s Unconventional Performance Database ties its findings to audited financial reports and publicly reported production data to ensure the data’s validity.

    TRACKING THE PERFORMANCE OF COMPANIES OPERATING IN NORTH AMERICAN SHALE BASINS

    BCG’s Unconventional Performance Database (UPD) consists of comparative financial and operational performance data for many companies operating in North American shale basins. It covers eight basins and reserves in the U.S. and Canada—Bakken, Delaware, Duvernay, Eagle Ford, Haynesville, Marcellus, Midland, and Niobrara—and includes at least five major players operating in each. We built the UPD from the investors’ perspective, looking at where capital was invested and the returns were generated. We focus on variables that are critical determinants of companies’ financial results, including development capital costs, production, price realization, operating expenses, and general and administrative expenses. Unlike many outside-in benchmarking studies, we tie our findings to audited financial reports and statements and publicly reported production data to ensure the data’s validity. Our objective is to break down companies’ financial results for a given unconventionals program (that is, a group of wells in one part of a play) into the main drivers of value and help identify performance “hot spots.”

    The database also includes basin parameters (such as production forecasts and operating-cost benchmarks) and basin-specific well characteristics. (See the exhibit “BCG’s Unconventional Performance Database Includes Detailed Basin Characteristics.”) Those include, for each operator, the average well’s cost, vertical depth, lateral length, number of fracture stages, 30-year estimated ultimate recovery, 30- and 90-day initial production rates, composite type curves, and other characteristics.

    exhibit

    Our database reveals that there are material differences in the returns offered by individual basins, reflecting differences in the respective basins’ geological characteristics, development and infrastructure requirements, potential products, local market pricing, and other factors. More striking, however, are the enormous differences in financial results between the top- and bottom-performing players within each basin or reserve. (See Exhibit 1.) In the Marcellus Shale, for example, the average after-tax return on wells ranged from 19 percent for the bottom performer to 65 percent for the top performer. Such divergence is also evident in smaller, less developed basins: in the Delaware Basin, for example, the bottom-performing company had an average after-tax well return of 17 percent, while the top performer had a return of 66 percent. For top performers, this difference is equivalent to a savings of $2 million in capital costs per well (in a basin where well costs, on average, range from $6 million to $8 million) and a doubling of wells’ estimated ultimate recovery (EUR), or lifetime production.

    exhibit

    These differences in financial returns are partly driven by variations in the geological characteristics of the companies’ holdings. But they also, critically, reflect sizable differences in the technical and operational practices, and the cultural norms and behaviors, embraced by the various companies as each strives to find an optimal balance between dollars spent on development efforts and dollars earned through recovery.

    We believe that there is no single optimal approach to achieving best-in-class performance on these fronts. Rather, it is important to focus on the company’s internal rate of return (IRR) per well—that is, what the company gets out of each well versus what it puts in—and then look for cross-functional opportunities to improve it. (Optimizing gel loading and proppant type in hybrid fracs in order to reduce stimulation costs without harming production is an example of such opportunities. Another example is rightsizing artificial-lift designs to reduce capital expenditures.) Best-in-class operators buttress this orientation with a culture of continuous improvement and structured mechanisms that enable them to constantly test, learn, and improve, thereby boosting well IRR even further and on an ongoing basis.

    Return calculations are based on incremental economics, excluding acquisition and midstream costs. Calculations assume New York Mercantile Exchange (NYMEX) strip prices as of December 1, 2014: a West Texas Intermediate oil price of $70 per barrel and a Henry Hub natural-gas price of $3.97 per thousand cubic feet in 2015.
    On the basis of prevailing prices for oil and gas (the NYMEX price for West Texas Intermediate oil for February 2015 was $50 per barrel; the Henry Hub price for natural gas was $3.90 per thousand cubic feet) at the time of writing.