The rapid growth of unconventional resources in North America, especially shale gas and liquids, has generated both enormous enthusiasm and deep skepticism. Some have proclaimed that shale represents extremely low-risk, manufacturing-style opportunities, while others question whether it has, or ever will, truly yield the anticipated returns.

The collapse in regional natural gas prices has driven home the marginal nature of these assets, with their substantial exposure to commodity-price risk. This in turn is forcing a debate about how best to allocate sparse capital between conventional exploration programs and unconventional resource projects, causing the industry to rethink how it characterizes unconventionals.

With over a century of experience, the oil and gas industry has widely adopted frameworks and tools for understanding and quantifying risk and rewards for conventional exploration opportunities. But the industry has yet to clearly characterize unconventionals, and it lacks commonplace techniques for evaluating unconventional investment opportunities against conventional options within the overall upstream portfolio concept.

No serious evaluation of conventional exploration opportunities would ignore inherent finding risks, and when evaluating performance it is only proper to look at full-cycle economics, which can yield returns of 15% to 25%. As shale plays emerged, however, it became a widespread practice to base analysis on point-forward, type-well breakevens and rates of return—often touted in the range of 30% to 70% (and higher!). This disconnect stemmed mostly from analysts’ focus on understanding commodity-price and investment dynamics for established plays, combined with independents’ wish to emphasize the potential profitability of their shale drilling programs.

Using point-forward and average well economics may be appropriate when the distribution of well performance is well established and one is considering the development potential of an already captured and proven asset. But this custom of using type curves and point-forward analysis contributed to the perception of shales as largely homogenous formations with repeatable well results offering close to zero risk.

With perceived low risk and outstanding development economics, competition among buyers drove up the price of entry for proven shale plays, enticing companies to move into the next big emerging play before access costs escalated. When considering entry into an unproven position or play, however, the “no-risk, high-return” mentality is dangerously flawed, although until recently it was masked by high natural gas prices.

To address this issue, operators need to consider where in the asset life cycle an unconventional opportunity sits, and build appropriate risk into the analysis. Although it is an imperfect exercise, mapping the conventional life-cycle and risk concepts to unconventionals is key to successfully characterizing these opportunities.

Life-cycle frameworks

Conventional exploration prospects progress through distinct life-cycle stages: exploration, appraisal, development and production, with clear transitions for each stage (exploration well discovery, final investment decision (FID), first production and abandonment). Following the appraisal process and having sanctioned the project for development, E&Ps typically no longer apply subsurface risk to the entire project. Uncertainties and risks remain, and are worth modeling as sensitivities, but they are risks to an asset’s valuation, not to its technical and commercial viability.

The two biggest differences in applying a similar life-cycle approach to unconventionals are: the transition between stages for unconventionals is far less discrete than with conventional prospects; and de-risking is a slower and a more gradual process.

For unconventionals, Wood Mackenzie defines concept, pilot, ramp-up and exploit life-cycle stages. During concept, the operator tries to identify prospective unconventional resource targets, which do not have any production history from unconventionally drilled and completed wells on which to base a commercial evaluation. To fully de-risk the concept, the E&P must run a pilot drilling program to work out the engineering and cost-benefit tradeoffs that establish repeatable, economically profitable results.

During these early two stages, it is unclear whether a commercial-scale development program will be viable. Thus, just as a conventional field’s development cash flows are risked, the same process should be undertaken on the potential shale development cash flows.

Operators have not traditionally talked about making a final investment decision on a shale asset; however, there is often a ramp-up period, after the pilot stage, in which financing is secured, rig fleets and completion crews are contracted, leases are drilled to hold, midstream is built out, etc. The project then moves into the exploitation phase, when development drilling must continue to maintain production, due to steep decline curves.

During these later stages, the “percent developable” acreage and well performance deviations represent the major remaining subsurface risk that unconventionals face that conventional fields do not. Percent developable is a direct determinant of the number of well locations (hence remaining value) of the undeveloped portion of the acreage. These later-stage risks can be quite substantial. For example, a leading U.S. operator of shale plays has applied factors of 30% to 75% developable to its established positions.

The value and returns from conventional and unconventional assets share the same primary drivers: price, production volumes, capital costs and fiscal terms, and they are equally impactful across the life cycle. The key driver of value that evolves across the life cycle of a project/prospect—ultimately the variable with the largest impact on valuation—is the overall commercial “chance of success” (CoS), quantified by combining technical (Pg) and commercial (Pe) risks.

Shale CoS < 1

The evidence is mounting that shales are more risky and less homogenous than originally conceived. Out of over 30 shale gas plays in the U.S., only 10 have emerged from pilots into full development mode.

While the jury is out on several plays still being tested, another 10 have arguably been proven noncommercial or face numerous subsurface and aboveground challenges. Stipulating that there is a “failed play” for every proven shale suggests that the chance of success for an entire play could be around 50%.

Even when shale plays undergo serious pilot efforts, they do not emerge in their entirety as a commercial play. The Niobrara is a prime example of a play in which heterogeneity has meant only a subset of the pilots conducted in the play are leading to commercial development.

The pilot stage is also one of delineation of core areas and sweet spots, and even in largely homogenous plays, the percentage of acreage that is commercially viable is far less than 100%. For example, success in the Eagle Ford is concentrated along the narrow gas-liquids transition window that runs down the middle of the play.

Through a number of case studies and M&A transaction analysis, Wood Mackenzie has “back calculated” a range of implied CoS factors. At the start of the concept stage, CoS may be around 10% to 20%, and at the start of the pilot stage anywhere from 20% to 50%. Although, as noted, there is no exact point of transition from pilot to ramp-up, eventually the acreage is proven, well performance is established, and CoS approaches 100%.

Relative to conventional exploration, two key points stand out. First, unconventionals are just as risky as conventional exploration (commercial success rates for conventional exploration are generally 25% to 30%). Additionally, CoS is de-risked far more definitively and sooner in the life cycle for conventional opportunities than for unconventionals.

By the end of the exploration phase, most conventional prospects’ CoS is near either 0% or 80% to 90% (except for marginal fields). For unconventionals, however, CoS improves only gradually across concept and pilot stages. The implication is that a lot of the upfront capital of a conventional prospect is deployed during the less risky appraisal stage, while capital invested during the pilot is still very much at risk, resulting in much higher “costs to condemn.”

It is possible for operators to create value at any stage in the life cycle. For example, consolidating positions and excelling at driving cost efficiencies can create value during the later stages in a play. However, the biggest single opportunity for value creation arises from derisking the acreage: turning a land position originally leased for less than $500 per acre into a proven property that can fetch anywhere from $5,000 to $25,000 per acre.

The key value drivers evolve over the life cycle of the project, driven primarily by CoS and the amount of capital put at risk. For example, during the early stages when risk is high and land costs are low, maximizing the acreage exposure provides significant value, in the success case, as material upside for a large number of well locations and hence value creation. However, during the later stages, when acreage access commands a premium, percentage developable and well spacing are the key drivers of the number of well locations.

Operators that excel at ramping up quickly or speeding up the learning curve can use these capabilities to drive value after a position is derisked, but these effects are swamped by pilot-stage risks and uncertainties if they enter a play early in its life cycle. At these stages, the amount of money spent on the pilot and the time it takes to gather enough information to commercially prove up the play are much more important factors.

Recognizing the unconventional life-cycle stages and risk factors enables more of a like-for-like comparison between big exploration and shale opportunities. Once one factors in full-cycle costs, CoS, and adjustments for percentage of commercial acreage, the internal rate of return (IRR) on a hypothetical Eagle Ford project decreases from 27% to 15%, more on par with conventional exploration.

Portfolio allocation

Using the life-cycle framework enables one to acknowledge and account for the fact that most investment opportunity comparisons are fundamentally not like-for-like. The very real allocation decision facing many large E&P companies today is between their conventional exploration programs and existing shale asset developments. To consider such a case, Wood Mackenzie conducted a hypothetical exercise for a company deciding between allocating $1 billion per year over five years with the choice of either a high-impact exploration program in the Gulf of Mexico (GOM) or developing an existing, proven Eagle Ford shale position.

The two options offer very different value propositions: in terms of reserve additions, $5 billion spent on GOM exploration may discover around a billion barrels of oil equivalent (BOE) from new fields (discovery costs in an achievable $5 per BOE range). In the Eagle Ford, this same amount buys almost 600 wells, which, if assuming an average EUR of 900,000 BOE, yields only half the reserves at around 530 million BOE.

Using Wood Mackenzie default economic assumptions and analogs for the Eagle Ford and GOM, we modeled the production and value of both programs. The GOM program results in substantially higher net present value (NPV) at more than $5 billion (net of the exploration costs), while the Eagle Ford project yields only about $1.5 billion.

Unconventionals such as the Eagle Ford do offer some advantages, including nearer term production, in this case reaching a peak production rate of 130,000 BOE per day within five years. Longer development cycle times for deepwater projects mean the GOM program would not reach its peak production of 174,000 BOE per day for 11 years. Earlier production provides revenue that can help fund capital requirements, meaning the maximum net cash impairment of the Eagle Ford project would only be $2.8 billion, while the deepwater program would require $8.5 billion.

Because they are so different, the investment profiles of conventional and unconventional assets can be highly complementary and can work in tandem at a corporate level. Early production from unconventionals can fill the void of long conventional cycle times. This, in turn, provides early positive cash flows, helping to offset the otherwise deep, standalone cash impairment of a conventional opportunity.

Conventional and unconventional assets can also be complementary within a portfolio in that they offer different risk profiles (types of risk and timing), theoretically providing a potential source of diversification for the overall risk profile of the portfolio. Given their typically much larger acreage footprint, unconventional assets can also provide a great deal of resource upside potential with future technology improvements. The key is managing unconventional assets within the portfolio with full appreciation of their life-cycle stage and risk characteristics.

Project sensitivities

It is also critical to recognize how the marginal nature of shale projects will impact a portfolio’s exposure to commodity, volume and cost risks. When comparing later life-cycle stage assets, one must consider the usual key uncertainties: volumes, price and cost. Here, the valuations of the unconventional assets are far more sensitive, mostly due to their significantly higher breakevens.

For example, a Bakken project may have a breakeven in the $50 per barrel range, versus a large discovered Gulf of Mexico field with a breakeven around $15 per barrel. In this instance, a 20% change in the volume of the GOM field may result in a 30% change in NPV, but a 20% change in well EUR in the Bakken will swing the NPV plus or minus 110%.

A change in price has an even larger impact. This level of volatility in commodities is commonplace and volumes are highly uncertain, but while the conventional field economics can suffer a setback, the Bakken project is at risk of being uneconomic. For many shale-gas producers, this phenomenon is all too real. In this light, unconventionals are riskier than conventional fields, especially during the development phases.

The value of unconventional projects is also far more sensitive to costs than for conventional projects. In the case of Opex (operating expenses), the impact on conventional projects is insignificant, whereas for unconventionals Opex is still relevant. This may represent an underappreciated long-term risk for unconventionals, as there is limited experience with and information about the long-term operating costs and maintenance requirements for the tens of thousands of shale wells being drilled, particularly for those producing liquids. On the plus side, technological advantages that reduce costs, even incrementally, have the potential to greatly enhance asset values.

Conclusion

With the benefit of experience, we now understand that unconventional resource plays and shales in particular are just as risky as conventional, high-impact exploration. Additionally, the nature of their risk evolves in a less definitive manner over their asset life cycle, and the residual risks (percent developable) and uncertainties (marginal economics) are more severe for unconventional assets even during the development stage.

There is a role for unconventionals in the corporate portfolio, so long as companies employ frameworks and approaches for evaluating risk that enable them to compare unconventional and conventional opportunities on a near like-for-like basis. With so many variables and unknowns in unconventional asset modeling, it is critical to identify which ones deserve the most upfront scrutiny. This is largely determined by the asset’s current life-cycle stage.

With unconventionals, there is a temptation to focus on the more well-understood engineering and operational assumptions; however, it appears more and more that strong technical and commercial evaluations of risks and uncertainties are far more important.

Preston Cody joined the upstream consulting group at Wood Mackenzie in May 2011. Previously, he was a manager in the oil and gas group within the strategy and operations practice at Deloitte.

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