In an era of capital-intensive resource plays, how can small independents not blessed with abundant capital or large prospective lease positions create sustainable value?

One answer is to apply a portfolio of contrarian strategies in conventional natural gas basins that today are being overlooked. The end result can yield a very different company than management teams might be used to, but one that can profit handsomely if the strategy employed is well executed.

A prevalent line of thinking in E&P management is, "Sell the legacy, buy the resource." But the contrarian philosophy holds, "Buy the legacy, exploit the upside." And where better than in conventional basins?

This approach rests on the following theses:

• Recent developments in fracing technology in source-rock/shale plays are creating a significant movement of capital away from conventional "bread-and-butter" basins, especially in natural gas. A result is high-quality deal flow, with upside.

• In tandem, and for the past several years, capital allocations for reworking conventional low-productivity wells have been redirected to far costlier shale or deepwater offshore plays, leaving behind candidates with low risk and high internal rates of return (IRRs). This trend is reminiscent of the majors' exit from onshore conventional basins circa 1986-1990.

Timing

Value creation belongs to first movers who capture niche opportunities, often by anticipating capital flows into or out of oil versus natural gas, and/or various play types.

In unconventional plays, first movers capture value by acquiring leases early and on the cheap, later joint venturing or flipping the same acreage.

Today, the first-mover advantage can also belong to a focused contrarian targeting conventional basins that offer deal flow and a high population of wells with neglected, high-IRR workover candidates, available at bargain prices.

Commodity opportunity

The flavor of the moment is oil and natural gas liquids (NGLs). A prevalent view is that the price of natural gas is forever doomed to 20:1 Btu equivalency. A contrarian view is more balanced. There's little doubt that oil and gas commodity prices will remain cyclical, owing in no small part to the nature of capital flows. Capital naturally follows perceptions of sustainable upward price movements, thus driving the supply side of the price equation. Capital flows are an important factor in judging the direction of commodity prices.

Clearly, compared to competitive fuels, natural gas prices on a Btu basis remain significantly depressed at 18- to 20:1, largely as a result of burgeoning supplies from high-productivity shale-gas wells. At the same time, decline rates on most of these projects are 70% to 85% in the first year.

At today's wellhead prices, many pure shale-gas plays are at or approaching negative all-in IRRs. Once drilling to hold those overpriced leases is completed, the high hyperbolic decline rates will rapidly diminish each well's existing production levels. Together with higher demand, this may be contributing to the recent migration of storage levels back to historical five-year averages.

These forces suggest a gradual increase in natural gas prices to perhaps $6 to $7 per thousand cubic feet (Mcf), at which time dry-gas shale economics swing back to positive. The increases likely will be gradual, because active shale drilling in high-liquids-content reservoirs will also produce natural gas, almost as a by-product, and accordingly will dampen the rate of any cyclical upturn. That said, economic returns on low-margin natural gas wells in conventional basins with even modest upticks of $1 to $2 per Mcf can more than double PV-10 values and unlock more underexploited workover opportunities.

Deal flow

In unconventional plays, identification of a basin-specific opportunity is followed by the inevitable land rush, with companies competing fiercely for the next section of land. The latecomers are left paying significant premiums.

A contrarian approach is to access deal flow in conventional basins by partnering with local, smaller independents and tapping into their deep knowledge about the production they may have worked for decades.

A prevalent practice is to operate and own 100% of the working interest in production, if possible. The contrarian view says, "Control your destiny, and localize your operations partner." Here is a road map for how that might be accomplished:

• Select local operations partners that are geographically focused, with proven experience and a good reputation in the community;

• Develop reciprocal areas of mutual interest (AMIs) where practical, to enhance deal flow;

• Execute joint operating agreements (JOAs) that provide for Council of Petroleum Accountants Societies overhead charges only;

• Negotiate an upside with the local operations partner on an after-payout basis;

• Work toward having each operations partner participate in the purchase with 25% of its own capital;

• Ensure that the JOA provides budget and operations control through approvals by a majority of the working interests, thus leaving you in control and minimizing overhead;

• Require monthly updates and daily reports for workover operations;

• Prior to each acquisition, have your internal engineer and your operations partner scrub all available well files from the seller.

In summary, control your destiny, but capitalize on the knowledge of local partners who are far more familiar with the targeted acquisition than you could ever be.

Tailor metrics to production

Unconventional plays set internal rates of return as a primary metric. Hyperbolic decline curves of 70%-plus necessitate IRRs. A conundrum for many players has been matching commodity cycles with the imbedded lead times between initial lease acquisition and the first 18 months of production. Likely, many a purchaser of Haynesville leases at $15,000 an acre, when natural gas hovered north of $10 per Mcf, is having second thoughts at today's price of $3.50 at the wellhead.

Contrarians in long-lived conventional-basin production see three clear pluses in today's market: the ability to hedge production in contango markets; the serendipitous benefits of rising prices; and increases in recoveries from technological advances brought to bear on the remaining long-lived reserve base.

In many conventional basins, especially gas-focused basins, lease operating expenses are high, and margins are low. However, consider the impact of even modest natural gas price increases, especially on PV-10 values. These values can be meaningfully increased with even modest upticks in gas prices or a well-orchestrated hedging program to elevate revenues using the forward curve. For example, in the Hugoton Basin, the PV-10 on an 80,000-cubic-feet-per-day producing well is 59% higher at $4.50 per Mcf versus a $3.50 deck. At $5.50, the increase in PV-10 is 118% compared with a price of $3.50.

On the technology side, only a decade ago the Permian was considered a mature producing basin. Today, myriad technologies have unlocked new formations, enhanced existing producers and transformed the basin into a virtual technology playground.

Thus, the contrarian view advocates passing on the resource plays and focusing on bread-and-butter, non-operated natural gas wells. It seems like almost a sacrilege in today's market, doesn't it? At the end of the day, however, this portfolio of contrarian strategies can produce a highly profitable enterprise, with low overhead and access to high-quality deal flow, by using local operators as partners. Moreover, the acquired production is likely to have numerous neglected wells, acquired at bargain prices, from which local knowledge can unlock high IRRs.

Finally, a focus on lower-productivity natural gas wells with lower margins at current prices can position the contrarian for a significant rise in asset value as commodity prices increase or as new technology arrives on the scene.

What's not to like in being a contrarian?