Author’s note: Content on the geological considerations of petroleum resource management was redacted and re-posted elsewhere in order to expand more on the resource fundamentals there and the business fundamentals here.
- The upstream business cycle can be sub-divided into five functional areas: Exploration and Evaluation, Development, Production, Marketing, and Retirement.
- The exploration and evaluation functional area creates potential value by discovering quantities of petroleum and reducing geological uncertainty.
- The remaining business functional areas realize geological value potential by adhering to more closely to the cost-centric logic of conventional value chain analysis.
- Integration between business units maximizes the value potential of an exploration and production concern.
- Markets for upstream assets are minimally inefficient; retail investors must think outside the box if they hope to compete with sophisticated and well-capitalized institutions.
Figure 1: Coyote Hills, California
Source: Coyote Hills, California. Lee Alban Fine Art.
Different petroleum exploration and production (E&P) businesses operate differently depending on their focuses and asset bases. Major differences can also be observed between various operators within a single basin. However, their business models are all strikingly similar: get oil and gas out the ground and sell it to the highest bidder. A generalized upstream business model has five functional activities: exploration and evaluation (E&E); development; production; marketing; and retirement. The E&E function essentially drives the process of identifying opportunities for potential value creation — it also broadly includes the evaluation of assets for acquisitions and divestitures (A&D). The remainder of the business functional areas support the exploitation of this value potential. In this way, the exploration functions abide by the principles value configuration theory 1, whereas the production abides by conventional industrial logic according to Michael Porter’s value chain framework.
It is notable that an upstream operating concern which is rationally integrated into a larger petroleum value chain does not need to be particularly good at either activity in order to create value.
The Core Functional Areas of Exploration and Production
A generalized upstream business model has five functional activities: exploration and evaluation (E&E); development; production; marketing; and retirement. The E&E function consists of acquiring and analyzing geological data, securing leases, and drilling test wells on prospective petroleum properties. Once a prospective property has demonstrated sufficient economic potential, E&P companies move into the development phase which includes all business function involved in commercializing a given quantity of petroleum within a given area: additional well drilling, well completion, and investments in related infrastructure. Once wells have been drilled and completed, they may begin to produce economic quantities of oil and gas, or they may not. The marketing phase consists of bringing the produced quantities of petroleum to the most advantageous market. The petroleum project life cycle concludes with the retirement of producing assets.
Figure 2: Upstream Business Phases and Associated Costs
Exploration and Evaluation
E&E broadly includes business functions which intend to produce discoveries and/or reduce geological uncertainty of previously discovered resources. Financing activities, such as A&D of prospective and producing hydrocarbon properties, are therefore a logical extension of these functions.
A typified production cycle begins with the E&E of prospective resources (i.e., resources which geologist believe to be present, but have not necessarily confirmed the existence of). There is no standard managerial process by which properties are evaluated, yet the technical methods and end-states are fairly consistent throughout the business. Under a typical scenario, managements will assess the potential for resources based on available data, such as geological maps and production data from neighboring properties. Management may then direct landmen to acquire exploration leases and then may direct geologists to acquire and then analyze relevant geophysical and seismic data. If geologist believe that one or more pay zones (i.e., a geological feature which contains economically and/or commercially producible quantities of petroleum) may be present, management may direct drillers to drill test wells. Well logs and core samples from the test wells will further confirm or refute the presence of a pay zone. If management ultimately believes in the property’s economic potential, they will direct landmen to acquire production leases.
In a 2001 article in the Oil & Gas Financial Journal, Roberta Olmstead claims that exploration outfits are best understood as value shops, as espoused by value configuration theory, in which value creation is a function of skill, information asymmetry, and a little bit of luck. She posits that because “it costs about the same effort to make a large discovery as one that is barely commercial… the distinguishing characteristic of the successful exploration outfit is not lowest costs.. [but] is rather [in] making significant discoveries, preferably as often as possible.”2. This contrasts with the remaining E&P functions which adhere to the more rigid industrial logic of the archetypal value chain, espoused in the works of Michael Porter, in which cost, scale, and capacity utilization are the core value drivers.
Figure 3: The E&E Cyclesource: https://ugmsc.wordpress.com/2011/03/30/one-day-course-review-hydrocarbon-prospect-in-western-indonesia/
During the development phase, additional wells are drilled and completed, and the required infrastructure is put into place to bring the drilled and completed wells online.
The drilling and completion (D&C) sub-phase consists drilling additional wells and completing them; completion consists of all the steps required to bring wells into production. Drilling and completion is usually the most capital intensive step. According to one estimate, “spending on completion typically accounts for 50–60 percent of the total development cost of shale wells”3. For conventional reservoirs, well completion consists of casing the well bore and cementing the liner in place. Unconventional reservoirs require specialized infrastructure and/or completion techniques to commence the production phase. For example, the use of horizontal drilling and hydraulic fracturing (i.e., fracing) on shale results in a synthetic petroleum reservoir system. Other specialized completion techniques include increasing permeability of rock layers through the use of perforation charges and matrix acidization, and reducing the viscosity of bitumen through steam injection.
Before the commencement of the production phase, wells must be tied into production infrastructure. The joint process of core asset development is often referred to as drilling, completion, equip and tie-in (DCEI).
It is also often necessary to invest in significant additions to plant, property and equipment (PP&E) — including processing, gathering, and transportation infrastructure — in order to commercialize quantities of recoverable petroleum. Size of the project, proximity and access to critical infrastructure, and the requirements for specialized recovery and processing are key factors in assessing the types of infrastructure which must be developed for a given project. For large projects, management may require additional well-level due diligence after drilling and completion before sanctioning the development of any infrastructure required to commercialize the petroleum. For large offshore projects, the development phase only can take several years to complete. For smaller projects, the investment cycle is significantly shorter and the consequences of a single dry hole are not as severe, so management may pursue D&C and any additional capital development simultaneously.
The capital heavy natures of the E&E and development phases – jointly known as finding and development (F&D) – bring significant economic risks. Although advances in technology have reduced geological uncertainty, resource depletion has made it increasingly difficult to locate desirable properties. In general, the front-loaded nature of investments in oil and production and the long lead-times required for projects to reach commercial maturity means that changing economic conditions, such as lower commodity prices, can turn oil wells into multi-billion dollar sinkholes.
The emergence of unconventional on-shore resources (i.e., tight oil and gas, including shale) in North America (NA) has shifted the balance of power away from long-term projects, however. A typical NA shale well can be brought into production within several weeks, and efficiencies are still improving. Moreover, the specter of drilled-uncompleted wells (DUCs), which can be brought online relatively cheaply in literally days, means that the current price regime is bound to last at least awhile longer. Longer tail projects, such as deep offshore and bitumen mining, are just simply riskier and have lower expected returns in the current environment. Moreover, longer tail projects suffer endemically from budget over-runs. Eventually, NA shale wells will reach peak production whereupon efficiencies will decline, but the prolific geology of NA shale continues to surprise skeptics and optimists alike. Moreover, it is simply a matter of time before NA expertise finds roots on foreign shores; geology is a global phenomenon, of course. The online publication Drill or Drop? provides real-time updates on the global fracking phenomenon.
Once the viability of a well and/or project has been established and any necessary infrastructure has been put into place, the production phase begins. Production involves the operation and maintenance of the well and associated equipment. Wells will also typically produce varying amounts produced water (i.e., saltwater) mixed in with petroleum which must be disposed of in an environmentally sound manner. Produced water is often pumped back into the ground via nearby injection wells or transported to treatment facilities.
Typical operating costs during the production phase include payments to royalty owners and other non-controlling interest, non-income production taxes, gathering and transportation expenses, and lease operating expenses (LOEs). LOEs aggregate a number of line-items such as labor, waste-water disposal, fuel expenses, property taxes, injections of fluid and/or gases into the wellbore, as well as “normal maintenance on the pump and other equipment, replacement of any pipe or tanks as needed, compensation to the operator of the pump, and payment of any incidental damages to the owner of the surface rights of the leased property”4 5 6. Rig operators, managers, and accountants may exercise a significant amount of discretion in how they classify (i.e., aggregate, expense, capitalize, and impair) well and field-level expenses.
The amount of petroleum which a reservoir originally produces through natural occurring energy within the reservoir — for instance, via gas drive or water drive mechanisms (i.e., without external stimulation) — is referred to as primary recovery; for oil centric projects, about 10% to 30% of global original petroleum in place (OPIP) is produced during primary recovery. Natural gas recovery rates tend to be far higher during initial recovery, approaching 100% under ideal conditions.
Secondary recovery methods utilize injection of water and/or gas to maintain hydrostatic pressure. Produced water and gas injections to areas immediately beneath pay zones increase hydrostatic pressure within the reservoir system but will eventually result in an increased amount of produced water (i.e., watercut) in relation to petroleum. The increased watercut is a driving factor of rising per unit of production costs as wells mature (energy costs for pumping one gallon pure crude oil to the surface versus water are about the same). About 30-50% of global oil in place can be recovered through primary and secondary recovery methods.
Tertiary recovery methods, also called enhanced recovery (ER), include “injection of polymer solutions, surfactants, microbes, nitrogen or carbon dioxide, capable of influencing rock and fluid properties”7. The application of ER techniques has grown substantially over the last several years, likely due to the fact that many legacy reservoirs still have a lot of resource left in them, but are no longer commercially or economically viable under primary and secondary recovery. Tertiary recovery is characterized by low capital cash since much of the infrastructure is already in place (e.g., wells, pipelines, etc..) but high per unit of production operating costs due to the use of costly reservoir stimulants.
Figure 4: Petroleum Recovery DefinitionsSource: SPE 84908; The Alphabet Soup of IOR, EOR and AOR: Effective Communication Requires a Definition of Terms; SPE /87864
Eventually, all wells deplete to the point of their ultimate economic limit. The point at which a well is no longer economically and/or commercially viable is ideally when estimated fixed plus variable production costs exceed revenues. The ultimate recovery of OPIP is extremely situational dependent, being governed by: types of petroleum resources in place; geological forces which dictate reservoir formation and flows; technology employed; and market conditions. 100% recovery of OPIP for nearly any oil reservoir is neither technically feasible nor economically sound at this time.
The marketing phase occurs concurrently with production in order to bring petroleum to the most advantageous marketplace. Petroleum is a fungible commodity, a barrel of a given standard of crude oil on the marketplace is usually just that and nothing more. Of course, if one were to get at the molecular level — through the use of assays and gas chromatography — one might be able to detect discrepancies between price and the expected value of a given quantity’s yield. But on the whole, any two barrels of crude oil which meet a given market’s specifications and standards are virtually identical and therefore abide by the no-arbitrage principle — any price discrepancies between these barrels of oil can be attributed to variances in gathering, treatment and processing, storage, and transportation costs which must be incurred to bring their contents to market.
Even a cursory glimpse of the typical petroleum marketing functional business model reveals how little influence E&Ps have over price realizations — price is a key operating lever available to most other business models. Many E&P outfits therefore seek to reduce leverage to commodity markets through price uplift projects or hedging activities. Examples of uplift projects include: liquefied natural gas (LNG) liquefaction, transportation, and regasification facilities; gas processing and factionization facilities; and bitumen upgrading plants. Uplift projects can easily erode value propositions due to the significant costs incurred and prolonged project life cycles. Furthermore, while hedging can “lock in” advantageous prices and limit the effects of adverse market conditions, it is equally, if not more, likely to lock in disadvantageous prices and limit upside. All the world’s wisemen (economists?) still do not understand how to forecast future prices better than the combined efforts of a free and liquid marketplace — and even if they did, the market would find out and adjust to the new efficient equilibrium.
In order to actually create value through sales and marketing, a company must be able to create intangible value through branding and product differentiation. Although this discussion is typically limited to products and services found further down the petroleum value stream, an upstream petroleum company which offers differentiated (e.g., geophysical, process improvement, equipment leasing, etcetera) services to other upstream companies can create economic value which is much less dependent on current market conditions.
Forays into differentiated products and services may not scale very well though. Therefore rational integration within the larger petroleum value chain is still the principle means by which E&P outfits are able to capture value through marketing activities. It is sometimes sufficient to sell at a higher prices, even if costs are not as competitive as peers’.
Retirement of petroleum assets occurs when management decides to shutter production through a either a deliberate or ad hoc retirement process. This process is also referred to as plugging and abandonment (P&A) and/or asset retirement (AR) and/or closure and rehabilitation (C&R). The majority costs associated with retiring oil and gas assets are allocated to maintaining compliance with environmental standards. In an ideal scenario, management retires assets at their ultimate economic limits, but this is not always the case.
On Value Creation
Success in the commodity-driven upstream oil and gas business is extremely difficult. Business concerns are too often subject to commodity price forces beyond their own control. As such, it is difficult to differentiate those who were skilled from those who were lucky either with regard to timing and/or geology. Still, there are the vertically integrated companies — outliers which have managed to create and accrue long-term value throughout the cycles. Their secret is not in making the best discoveries, nor is it in maintaining the lowest cost of supply. Rather it in their abilities to transform raw commodities into premium consumer goods and then market those good advantageously. Integration creates synergies when relatively cost-advantaged sources of commodity goods are transformed into relatively premium goods, thereby maximizing retained revenues, and eliminating the need for intermediaries and redundancy. While integration can lead to efficiencies of scale with sizable barriers to entry, the ability to pull on the price lever is undoubtedly the most significant component of an integrated E&P’s economic moat.
In the exclusion of vertical integration, the core driver of value creation in the upstream business is maintaining a low cost of supply. Production-focused companies whose managers unrelentingly evangelize cost discipline and capital efficiency into corporate culture will tend to be oriented to long-term value creation. These companies, when you can find them, are likely to outlast the weaker hands during lean times and outshine during the boom times, and therefore are likely to compound capital over the long-run. Long-term capital compounders, in turn, tend to have long-term investment returns which are more resilient to price paid. I will caveat that, though: margin of safety has two parts: 1) the margin of safety afforded when paying for assets near to or below replacement and/or liquidation values; and, 2) the margin of safety afforded by purchasing a compounding asset which will eventually justify any potential over-payment.
However, production and production costs are well documented within many institutional data banks. Reservoir engineers generally understand how cost and production trends tend to evolve for given wells in mature producing areas. There is virtually zero edge to be had by retail investors in identifying and investing in historically low-cost producers. Moreover, historically low-cost producers that are trading at discounted valuations usually deserve to be cheap — they are mostly value traps.
Another means, which seems to be under-regarded by institutional investors, by which an E&P can maintain low future supply costs is through petroliferous discoveries. This is a logical extension of business unit integration, albeit more focused than in conventional supply chain analyses. And, fortunately for investors, past exploration success may actually be prelude. E&E success is a function skill, information asymmetry, and luck. Skill comes from experience; we might expect past success to continue based on skill. Information asymmetry is often a function of reputation — vis-vis, the positive feedback loop which comes with and brings success — i.e., “exploration shops with the best reputation get a first look at the best prospects, they are often the preferred partners, and they attract the best professionals.”8. In cases where success is attributable to informational asymmetry, we might expect that past successes are in fact conducive to future successes. And luck? The more that fortune favors the few, the less likely is it due to dumb luck, but rather the exposition of skill and asymmetry upon chance. Still, there will be lucky finalists in anything resembling a coin-flipping competition, even when it’s geological in nature.
Instead of immediately couching the upstream business in very specific terms used by analysts and cited in financial reports and investor presentations, I have attempted to impart a holistic understanding of how the underlying business model might create investment value. I believe that investors who understand the business model’s propensity to consume capital but also its ability to create wealth are more likely to recognize a value creator when confronted by one.
Still, this is harder than it initially seems. The reality is that reservoir engineers, analysts, banks, and institutional investors have access to vast and sophisticated resources, tools, and data to value upstream assets. There is also a lot of money chasing opportunity in the upstream space, which entails that retail investors must compete in an efficient and well-capitalized marketplace with little opportunity for identifying mis-pricings (i.e., inefficiencies).
A conventional investor mindset would be to imitate the professionals, but there is little hope in beating them at there own game. The sensible alternative is employ to unconventional approaches. Given some assessed shortcomings about typified approaches to capital allocation, an enterprising investor might adopt a more holistic sense of petroleum resource economics in order to more fully appreciate the true worth of upstream assets. As I previously mentioned, successful exploration outfits seem to be under-regarded even by sophisticated investors. Here are a few more areas of potential inefficiency to consider:
- Institutions rely mostly on reserve-based metrics for upstream valuation and lending; reported reserves are mostly an accounting tool used to justify current valuations and are therefore an ineffective proxy for actual value (more generally, industry-specific metrics are generally inferior to traditional value metrics in predicting future equity returns);
- Many investors are myopic when it comes to dealing with uncertainty, typically relying on a single price deck when in fact price evolutions are virtually indistinguishable from a stochastic process — Fooled by Randomness seems apropos;
- Institutional investors are prone to bandwagoning around trendy plays and basins, thereby driving up market values and leasing costs at the same time, all while attracting even more buyers. The ability to avoid cognitive dissonance in this bubblicious game of hot potato should be seen as an advantage;
- Sell-side analysis is generally undervalued for broadly-followed equities;
- Buy-side analysts typically aggregate well returns at very high discount rates in order to compensate for perceived risk and corporate overhead. Superficially elevated discount rates as proxies for risk compensation may lead to systematic undervaluation of long-tail and counter-cyclical investments; and,
- Markets, in general, tend to underestimate the long-term capital compounding effects of rational vertical integration throughout multiple phases of a commodities cycle and multiple commodities cycles.
Footnotes [ + ]
|1, 2, 8.||↑||Roberta Olmstead. Competitive advantage in petroleum exploration. Oil and Gas Journal. 23 April 2001|
|3.||↑||Mark Mills. SHALE 2.0 Technology and the Coming Big-Data Revolution in America’s Shale Oil Fields. Center for Energy Policy and the Environment. Manhattan Institute. 16 May 2015|
|4.||↑||Mark Winger. Valuing Oil and Gas Reserves: Part I. Dec 2014|
|5.||↑||MPG Petroleum. Oil & Gas Fundamentals|
|6.||↑||Eric Penner. The Truth Is Out There – Shale Production Economics – Variable Cost And Net Present Value. 12 Sep 2013|
|7.||↑||Mikael Höök. Depletion and Decline Curve Analysis in Crude Oil Production. Global Energy Systems. Department for Physics and Astronomy, Uppsala University. May 2009|