Since its peak of just over 3,300,000 barrels of oil equivalent per day (boe/d) in the early 1970s, conventional Permian Basin production gradually declined to straddle 1,600,000 boe/d in 2005. At that time, consensus held that continued declines would render the Permian irrelevant.

This narrative was overturned by the advent of shale drilling. In a little more than a decade, Permian production topped its historical peak, reaching a production rate of more than 4,100,000 boe/d. Much of this growth occurred in the last five years, with production increasing at an average rate of 15% per year, according to Rystad Energy. Today, the Permian alone represents over a quarter of U.S. crude production and has reclaimed its place at the epicenter of U.S. crude assets.

Comparing Permian-specific performance

The entire story has yet to be told in terms of ultimate cash returns, winners and losers, but it is clear that operators are betting big on the Permian, whether they subscribe to a lower-for-longer or lower-forever oil price model. With the big bets and attractive breakeven prices, is everyone a winner in the Permian?

From a cash returns perspective, this question remains unanswered for the time being. Most pure-play Permian operators find themselves in cash-challenged positions. Operators primarily use debt-derived sources of cash to drive production increases through aggressive capex programs, the levels of which outstrip operating cash flow.

Numerous ways exist to measure success in the Permian. To separate financing decisions from operational performance, this examination is based on earnings before interest and taxes (EBIT).

First-half 2017 results for Permian pure-play operators yield an estimated $18/boe difference between the highest-EBIT and lowest-EBIT players. This gap in EBIT is the result of varied performance across four categories: depreciation, depletion and amortization (DD&A); price realization; opex; and selling, general and administration expenses (SG&A).

DD&A makes up 50%, or $9/boe, of the difference in EBIT. Though an accrual-based, non-cash expense, approximately half of this is addressable, as it’s driven by well cost, with the remaining portion driven by acquisitions and activity.

The highest EBIT operator considered here has an average well cost of $5.7 million in 2017, whereas the lowest EBIT operator spent an average of $7.3 million, according to the BCG Unconventional Performance Database. This gap can be closed through the combination of an agile organization to implement factory-model operations, along with a capital program based upon lean, standardized design principles.

At $5/boe, price realization makes up 28% of the difference in EBIT. Though a certain component of this realization is driven by the hydrocarbon mix of production—unaddressable on a point-forward basis—maximizing the netbacks for each hydrocarbon stream with a sound commercial strategy is addressable, and often underappreciated. Moreover, a successful hedging strategy can also be a useful way to manage risk and complement an operator’s overall commercial strategy.

Opex makes up 15%, or $3/boe, of the difference in EBIT. Levers within this category include transportation costs, supply chain effectiveness and production optimization. Managing this cost category is well-suited to centralized, cross-functional operations centers that support integrated decision-making for predictive maintenance, optimized logistical support and reservoir management.

SG&A makes up 8%, or $1/boe, of the difference in EBIT. In 2015, SG&A made up 20% of the EBIT gap at $4/boe. SG&A reduction has been a major focus for operators since oil price plummeted. Operators have created leaner organizations, with both technical and support functions affected. Though progress has been made to close the SG&A gap between top and bottom performers, opportunity remains.

Practical strategies for operators

Permian executives face an urgent need to make responsible management decisions while attempting to differentiate their performance from their peers. Once they have established an acreage position, they must respect the geology while moving as thoughtfully and efficiently as possible to optimize netbacks for each hydrocarbon stream and reduce costs to maximize operating cash flow and EBIT.

What, then, should be the specific focus areas for operators in the Permian? Three topics: organizational design, field execution and a commercial strategy informed by midstream and downstream considerations. Commitment to these can result in a material change in each of the four EBIT levers.

Agile organization

Examination shows that a winning shale player designs its organization as an agile factory, with eight operational characteristics that are fundamental to enable it to thrive:

  • Returns driven: maximization of profitable, rather than absolute, production.
  • "Factory model" operations: predictability and speed of execution by reducing downtime, eliminating waste in process and ensuring a continuous flow of activity.
  • Basin-specific expertise: tailored plans for precise and efficient operations, informed by robust basin knowledge developed through talent retention and knowledge sharing.
  • Standardized design and execution: simplification of designs, specifications and processes to increase consistency, shorten cycle time, lower cost and reduce risk.
  • Unrelenting cost management: the capability and discipline to prudently manage necessary costs while providing full-cost transparency.
  • Collaborative, cross-functional teaming: shared goals and accountabilities that are aligned to a basin.
  • Performance management for accountability: key performance indicators and associated performance-management systems that drive financial and operational performance as well as ensure alignment of interests—for individuals and team.
  • Culture of continuous improvement: a collaborative, entrepreneurial culture that balances risk mitigation with innovation.

Adaptable execution

The best execution begins with the best plans. Time and time again, operations have failed to deliver due to the lack of proactive, intentional coordination among key stakeholders, specialized technical support functions, the field organization and service providers.

To improve field execution, leadership should focus on the following four characteristics to improve planning and provide sufficient flexibility.

Operating rules. These form a flexible blueprint. An operator must have a clear understanding of the activity levels appropriate at different price scenarios, as well as an understanding of the steps necessary to maximize operating efficiency at those levels. Companies should create development plans with trigger points for changes in activity level based on the economics of the land, the current pricing environment and available inventory.

Responsive supply. An operator should design contracts based on commodity prices and associated activity levels that are mutually beneficial to themselves and to third parties. Forging strong, collaborative relationships with suppliers can help operators gain early access to the best equipment, technologies and crews.

For example, one operator managed to save 15% on its facility costs by locking in a pad design and committing to a certain activity level. This allowed the supplier to have greater visibility into its own needs and pass savings along to the operator.

Culture that institutionalizes acquired knowledge. As the industry’s workforce turns over, the codification of crucial operational information, and the ability to effectively transfer knowledge to new employees, will be critical. The ability to maximize efficiency in the performance of tasks, whether through outsourcing, automation or the minimization of skilled personnel necessary to perform a given task, will also be key.

A critical enabler of these efforts in the shale industry is the advent of digital technologies that can cheaply collect, analyze and disseminate data in real time.

Integrated operations centers provide a scalable environment in which institutional learning can advance as cross-functional decisions can be made faster with high-quality data, analytical capabilities and operational stakeholders located in one place.

Dynamic staffing capabilities. Operators must find ways to strategically ratchet talent up and down. To accommodate lower activity levels, they may need to offer employees flexible and part-time work arrangements, including unpaid leave with benefits.

Companies must be similarly creative to ensure that they have sufficient talent available for higher activity levels. Staffing can be supported by digital technologies to aid a more flexible workforce.

End-to-end commercial strategy

Most E&P companies consider themselves to be simply “price takers,” with little to no influence over the realized prices for their streams of oil and gas production. However, through more than 100 conversations with industry players, it is clear that companies that develop holistic, value-chain-based commercial strategies can improve their realized prices by $1/boe—regardless of their hedging position—by using the following approaches.

Companies should define a clear midstream strategy. Determine how the organization will optimize value-capture from wellhead to refinery over the medium to long term—one year to five years ahead. By modeling production streams from wellhead to customer, an operator can assess opportunities and risks, crude flows, allocation to refineries, price-setting mechanisms and resulting wellhead prices.

Companies should build flexibility to participate in different downstream markets. They should develop market intelligence and execution capabilities across geographies to quickly shift volumes based on price. To optimize value capture, they should consider volume projections, infrastructure, competitor economics and market evolution.

Companies can create organizational agility to react to commercial signals. This can be done by closely connecting commercial and asset teams to react to, and profit from, changes in the market. Often, there is a decoupling between formation of commercial terms and an operator’s ability to strategically manage the contract over its lifetime to maximize value.

Closing thoughts

Despite having the best economics in North American shale plays, operators in the Permian still display a range of performance when it comes to price realization and cost optimization. The highest and lowest EBIT players frame an $18/boe range in profitability. If lower-performing, pure-play operators close this gap, an additional $3 billion in EBIT would be generated—at 2017 prices and production levels.

This type of performance convergence has been demonstrated in the Bakken Shale, so it is reasonable to expect similar convergence in the Permian—but only if companies take conscious action to capture and apply the knowledge gained.

It’s not easy, but it is possible to make money in the Permian. By committing to fundamental improvements across organizational design, field execution and commercial strategy, each operator can fully realize the potential of its geology and acreage position.

Paul Goydan is a partner in BCG’s Houston office with more than 15 years of experience. He currently leads the firm’s North American energy practice across the oil, power and renewables sectors. Ivan Kozak is an associate director in BCG’s Houston office with more than 15 years of industry and consulting experience. He is currently a member of BCG’s global leadership team for upstream transformation within the firm’s energy practice. Kristen Speicher is a senior associate in BCG’s Houston office. Prior to BCG, she spent five years in the oilfield service industry.

Comments