Ample reward available for early movers, fast followers

Michael McMahon, Pine Brook, New York City

The early innovators of the social networking world who revolutionized the way we interact have made fortunes. These entrepreneurs were able to pocket $25 million to $200 million in just a few years before moving on to their next big thing, leaving it to the Facebooks, Googles, Amazons, and eBays to invest the capital and expertise to transform an intriguing concept into a sustainable business.

In a similar manner, early pioneers in the US and Canadian oil and gas business have been able to identify and capture acreages in shale and other unconventional resource plays at a very low cost and flip their holdings to bigger companies, which then spend large amounts of additional capital to transform opportunities from prospective acreage to flowing oil and natural gas.

What sets the early movers apart? And how can those who buy acreage later in the game at prices that are sometimes five to 10 times greater than those paid by the early movers make money?

The answers to these questions can best be found by taking a close look at exactly how an early mover succeeds and examining how fast followers evaluate economics associated with large capital commitments to their initial purchase and subsequent development dollars.

Shale: Energy's new frontier

By now, most know the story of the "Father of Shale Gas," Houston's George Mitchell, as he cracked the code in the Barnett shale of North Central Texas and became an "overnight success" - 11 years in the making. Once the industry realized that rocks - previously considered impervious and as caps to keep hydrocarbons from leaking away - were a source of gas and oil production, the race was on. The ensuing leasing activity in shale-prone areas such as the Eagle Ford, Haynesville and Williston monumentally changed the way we view energy opportunities.

Of course, with the benefit of hindsight, the revitalization of the exploration and production industry in North America seems easy: look for basins where there have been significant amounts of production and then identify the shale that was either a source rock or a cap rock, or both. In practice, it can be easier said than done. But by examining these early explorers' keys to success in light of today's challenges, we can better understand how this revolution will likely impact E&P investment opportunities in North America going forward.

Since Mitchell's game-changing discovery, there has been an ongoing effort to build upon these early learnings. For example, we now know how essential good geologic identification, fast acreage acquisition at low cost ($50-$200 per acre), and good lease terms (five years initial term and two- year extension) are for investments to prove successful. And, as is true for any theory, it is important that it be tested. It is imperative to drill a number of validation wells to prove the technical hypothesis that oil and gas can be produced from the rock.

For those who master these advanced investment lessons, the reward has proven significant: Hilcorp Energy, in partnership with KKR, acquired 141,000 acres in the Eagle Ford shale area of South Texas and sold this position to Marathon Oil Corporation for $3.5 billion. Cordillera Energy Partners sold its position in the Granite Wash to Apache for $2.8 billion.

Another early mover is a company that Pine Brook invested in, Common Resources. In Common's case, the management team acquired acreage in the Haynesville shale region and ultimately sold this position to BG and EXCO for $446 million. Common also acquired acreage in the condensate window of the Eagle Ford and sold this position to Talisman for $360 million.

Anatomy of a success

In the case of Common Resources, the management team relied on vast amounts of technical data, subsurface maps, well logs, and production histories to identify areas where the right confluence of resource and rock properties held the potential for large amounts of oil and gas in place. Once they were comfortable in their "desktop analysis," they moved quickly to acquire sizeable acreage positions through a combination of leases and joint ventures.

Common drilled a number of initial wells using horizontal drilling and large hydraulic fractures. The early wells were euphemistically called "science wells" - another way of saying, "We know they are going to cost a bunch ($10 million to $12 million to drill and complete), and we hope over time and with experience we can get the costs down to a more manageable level ($5 million to $6 million)."

Common, like many early movers, weighed the merits of the hold-and-drill scenario vs. selling to a third party. In addition to the rate of return analysis based on original oil in place, recovery factors, optimum well spacing, decline curves, and oil and gas price scenarios, a number of additional factors were considered in the evaluation of this decision - not the least of which was the organization's dynamics. Common had been established to be an early identification and capture company. The staff of 33 was heavily weighted to G&G (geological and geophysical) skills. In order to prosecute a hold-and-drill strategy, the company would have to more than triple in size as it added drilling, completion, midstream, and accounting personnel.

The decision was made to sell. A formal process was conducted. Common realized a significant profit on its investment. Obviously, Common got a good deal. But did the buyers? The answer is "yes."

Return expectations change over the course of identifying and developing a resource play from exploration through development to production. Internal rates of return received by the early movers (like Common) when a project works are well over 50%. Over time, as capital is added (including the purchase of acreage by a "fast follower"), the rate of return decreases, but so does the risk. In the case of a company that buys with the intent of drilling and holding, Pine Brook estimates the returns are typically above 12% for proved undeveloped reserves and above 20% for probable reserves. So, in the case of the sale of Common to Talisman, for example, the outcome was a "win" for both parties.

One element that is sometimes overlooked in these early capture activities for shale plays is that not all first movers meet with success. We estimate that, of the plays and acreage that are acquired, only one in three prove to be highly economic. Just as in the traditional oil and gas exploration business (using seismic looking for bumps), the successful winning plays must be sufficiently robust so as to offset the cost of the unsuccessful plays.

Companies that elect to be early movers must be sufficiently well capitalized to stay in the game. We estimate that to identify and acquire an acreage position of scale so as to be attractive to the next company up the food chain, a minimum of 25,000 acres - and more likely as much as 50,000 acres - is required. Adding drilling and initial validation costs, a company must be in a position to allocate $50 million per play. This is not too dissimilar to an offshore exploration well in the good old days, pre ultra deep.

Who will provide the capital? And who will capture the economic rent?

So what are the implications of these unconventional oil and gas opportunities in terms of capital and sharing of economic rents among the various players? And how will public opinion and government regulation impact the pace and outcomes of this development activity?

The capital requirements are significantly larger than anything experienced recently in North America. Industry observers estimate that capital spending in 2012 on shale plays in North America will increase approximately 12%. Much of this capital will come from the same sources that have funded this activity over the last five years - the large majors, sub-majors, and international players. Furthermore, as the current plays mature, some will reach self-sufficiency so capital access should not be an issue.

Market forces will allocate the economic rents from this shale activity over time. In the recent ramp-up stage, service companies were able to capture an abnormally higher portion of the rent as they built capacity. In some cases they were able to earn payouts on their investment in less than one year. However, an inflection point has been reached as capacity has grown. Excess capacity in completion equipment is already dampening costs and will continue to do so, resulting in more normalized returns on a go-forward basis.

Midstream participants (gathering, processing, and transportation) have experienced both unusual opportunities (think trucking and rail activities to export crude out of the Bakken) and a favorable risk-reward relationship where those midstream companies that are able to sign up anchor tenants for their pipeline and gathering systems can leverage this advantage to generate high returns. But as these systems are built out, midstream returns will revert to more normalized rates of return in the 12% to 15% range.

Given the current price of oil, even adjusting for the WTI differential, there is enough margin for all participants to earn attractive returns. This, in turn, makes it easier to attract capital.

Clouds on the horizon?

The potential for public option and government regulation to slow activity and raise costs is a very real concern for investors and operators. The industry only has itself to blame for not creating a transparent process where those concerned with the potential for environmental harm as a result of hydraulic fracturing could be dealt with based on facts, not misconceptions.

All activity involved with the extraction of any resource entails the potential for harmful outcomes. The use of hydraulic fracturing to extract oil and gas from shale has the potential for contaminating water supplies. But, proper well design and wastewater handling protocols can reduce this risk to acceptable levels. The industry was late in disclosing the chemicals put into the well bore; late to have an adequate response as to how they plan to manage wastewater; and late to explain how they plan to minimize the risk associated with the release of methane into the atmosphere. The solutions are in hand, but considerable effort will be required to overcome the negative first impression created by not getting out in front of public awareness.

There is another impact that must be dealt with, the double-edged sword of activity, especially in areas not used to heavy equipment moving across country roads and around-the-clock drilling. The benefits to those who get the good jobs are obvious. In those areas where mineral rights are still connected to those who own the land, there are further direct benefits. But in areas such as Pennsylvania, Ohio, and New York, these mineral rights were severed from surface rights long ago. Consequently, these landowners often view this activity as having a negative impact on their way of life.

Certain government leaders are attempting to address this in a number of ways. A reasonable road-use fee, where the oil and gas companies pay a fee to repair roads and bridges, is one. In Ohio, Governor John Kasich has proposed a graduated severance tax on oil production, up to a maximum of 4%. The proceeds will be used to reduce taxes for all Ohioans. As the market matures, creative solutions will go a long way toward ensuring sustainability for all involved.

A winning formula

A great deal has occurred since George Mitchell's vision first became reality. The science has improved, the investment fundamentals have become better understood, and new regulatory challenges abound. The outlook remains bright. Early movers in the right area will still make money. Second movers who bring the capital and expertise to develop the resources responsibly can still find financial reward. And the public will continue to benefit from good jobs and a meaningful step toward energy independence. Yes, unconventional resources truly represent a real "win-win." OGFJ

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