TY - JOUR
AU1 - George,, Bob
AU2 - Cline,, Bill
AU3 - Seager,, Rawdon
AB - Abstract This article addresses the valuation of upstream oil and gas assets – hydrocarbon reserves and resources - within a conceptual framework intended to be clear to non-technically-trained or experienced readers. The first part of the article addresses in detail the mechanics of quantifying the underlying hydrocarbon volumes, translating these into (the expectation of) future cash flows which underpin value, and the incorporation of risk. The second part of the article focuses in more detail on utilizing the cash flow analysis to create a valuation opinion, and validating that opinion using other market metrics (which can also be used on occasions where the data required for a cash flow analysis is not available). It also comments upon a number of issues and considerations that come into play and may underlie the differences or be the cause of contention between parties who assert very different opinions of value. The whole valuation process requires bringing together a large number of considerations, many of which are subject to considerable uncertainty. Care must therefore be taken not to imply an accuracy in the opinion concluded which, in reality, will almost certainly have a reasonable range of uncertainty that sometimes can be quite wide. PART I - INTRODUCTION Whether it relates to investing in different forms of government bonds, or oil and gas assets, valuation is all about assessing risk and reward, and finding a price that reasonably balances these two that is ultimately reflected in the meeting of minds between buyer and seller in the marketplace. View largeDownload slide View largeDownload slide Before discussing the valuation of upstream oil and gas assets, it is helpful to start by understanding exactly what it is that is being valued. While there are specific circumstances where this might not be so, in the context of this article the upstream oil and gas assets referred to are not the platforms, wells, pipes and drilling rigs that may represent the tangible components, but the ‘intangible’ rights held by oil and gas companies. These rights are known variously by names such as Licence, Lease, Concession, Permit, Production Sharing Contract, and so forth and for simplicity they will be referred to either as Contract or Petroleum Contract. While the ultimate commodities sold are the oil, gas and other hydrocarbon products produced from the ground, and the wells, facilities, pipelines and so forth are required to extract these from the ground and get the hydrocarbons to market, without the right to produce and sell, everything else is often worth nothing. Thus, Petroleum Contracts represent the means through which rightsholders may monetize the future benefits of the underlying hydrocarbons, and (along with other laws) define the terms and conditions by which that monetization may take place. That having been said, the value of the Petroleum Contract is tied directly to the expectations of reward (and risk) from holding that Contract. Thus, while it may be that strictly speaking it is the Contract that has the value, the assessment of this value is achieved by analysing the underlying oil and gas assets. While the concept of valuing oil and gas assets is straightforward and, indeed, procedures for evaluating and formulating an opinion on value are well founded, the devil is inevitably in the detail. There are significant challenges in quantifying both reward and risk; the former is based on making an assessment by indirect measurement as it is impossible to quantify the volumes of oil and gas directly, and the latter is hampered by both the number, and interdependencies, of risks involved and that risk is a subjective measure that is itself incapable of precise measurement. The number of market transactions that take place and are adequately reported are finite, but do allow a degree of framing of opinion. However, rarely is there one that so precisely meets the timing and characteristics of another that is the subject of a valuation opinion that it can be used as an absolute indicator of value. Further, while there are publicly traded oil and gas companies, they are generally by their nature portfolios of assets and are insufficiently ‘pure play’ to allow more than opinion framing. The fact that a value cannot be validated precisely by obtaining it from a trading platform should not invalidate it. The fact that the valuation of exploration assets involves a greater degree of speculation than for producing assets does not make them worthless (witness some of the bonuses that have been paid in the very recent past). However, understanding the processes involved in forming an opinion of value, and how risk and uncertainty are incorporated, will hopefully assist in appreciating why there can be such varied opinions on the value of a single asset. This article addresses the valuation of upstream oil and gas assets—hydrocarbon reserves and resources—in two parts. The first part addresses the mechanics of quantifying the underlying hydrocarbon volumes and translating these into (the expectation of) future cash flows which underpin value, while the second part deals with all the nuances that exist in compiling those cash flows, and reflecting them within an opinion of value. The whole valuation process incorporates a large number of considerations, starting with geology and petroleum engineering in order to estimate the volume of oil and gas that is to be valued, through to corporate finance principles and probability theory in order to take into account the appropriate balance of risk and reward that will inform the ultimate valuation opinion. The net result of the number of individual processes involved, and the choices that have to be made at each process stage means that, in practice, there are probably more blue moons than occasions when a unique value can be determined. More realistic in virtually all circumstances is determining a range of values within which any value can be justified. Notwithstanding all the uncertainties involved and potentially wide range of conclusions that may reasonably be drawn, there is a structured process involved in the valuation of oil and gas assets. This article focuses on the assets themselves, rather than the value of a going concern1 holding those assets (even where these may be the sole significant assets of a company). Some opinions may stretch credibility by assuming risks (or the lack thereof) and outcomes that will rarely, if ever, be encountered. Others may try to imply an impossible accuracy by opining value to several decimal places. Reality is that all oil and gas asset valuations have a range of uncertainty, and that sometimes that range can be quite wide. The purpose of this article is to describe those components within a conceptual framework such that it is clear to non-technically-trained or experienced readers. Hopefully, some of the insights provided will assist in allowing what may otherwise seem a very opaque process and black art to become, if not always a thing of beauty, then at least an understandable and rational basis for estimating the value of oil and gas assets. As noted above, Part I of this article addresses the quantification of volumes and the building of one or more expected future cash flow streams, through a number of steps: Understanding hydrocarbons and traps. Quantifying the hydrocarbon volumes. Classifying the hydrocarbon volumes (reserves and resources). Categorization of reserves and resources. Incorporating a development plan with its related capital and operating costs, and timing. Building a cash flow, incorporating relevant fiscal terms. Assessing risk and uncertainty. Incorporating risk and uncertainty. Understanding hydrocarbons and traps While this article is not intended to be a primer on oil and gas evaluation, it is helpful to have a basic understanding of how oil and gas accumulations arise, and the challenges in defining them, in order to be able to understand better the uncertainties in quantification of volumes and the values that derive therefrom. Hydrocarbons is the name given to range of chemical compounds formed by the bonding of hydrogen and carbon. The range varies from the simplest and lightest methane gas,2 through liquid oil to very heavy, viscous and solid forms such as tar or natural bitumen. They may exist in the ground either separately, or with gas dissolved in the oil, or in a hybrid state known as gas condensate. Oil and gas exist in the pore spaces and natural fractures in rocks, not in large underground lakes. Further, they do not exist alone, and are mixed with water and other gaseous3 or liquid impurities. Typically, less than 25 per cent4 of the overall rock volume is occupied by hydrocarbons, water and impurities and, in the case of ‘tight’ or ‘shale’ reservoirs, this may be 5 per cent or less. Hydrocarbons are generated from the thermal maturation of naturally deposited organic compounds in what is known as the ‘source’ rock. Typically, these source rocks are shales or mudstones. The hydrocarbons that are generated as tiny oil droplets or gas bubbles migrate upwards over many millions of years into different rock layers known as reservoirs, the most common being sandstones and limestones. While for ‘conventional’ oil and gas accumulations, source and reservoir rocks are separate formations, ‘unconventional’ oil and gas exploitation blurs this distinction. Unconventional exploitation is not just about shales though, as it also includes very heavy oil (Canadian oil/tar sands and Venezuelan extra heavy oil being two well-known examples). A key distinction between conventional and unconventional exploitation is the nature of how the hydrocarbons have been trapped underground. As noted above, pore spaces in rock contain a mixture of (mainly) gas, oil and water. Gas and oil are both lighter than water and so, as they are generated, will attempt to migrate upwards towards the surface. This migration continues until they are trapped and can rise no further, or they reach the surface (so called ‘natural seeps’). Gas is lighter than oil so where both coexist in the reservoir, gas will lie above oil. Gas within an accumulation containing just gas, or where the volume of oil is limited to a small layer underneath, is known as ‘non-associated gas’. Gas within an accumulation consisting of a cap of gas over a substantial column of oil, or where it is entirely dissolved in the oil, is known as ‘associated gas’. In some jurisdictions, there may be different ownership or economic rights for associated and non-associated gas. Conventional oil and gas traps occur when the upward-migrating hydrocarbons encounter a layer of rock that is impermeable. Such impermeable rocks may be shales and mudstones like the source rock (although not necessarily being source themselves), or a barrier like salt. In situations where reservoir rock lies beneath an impermeable layer that has been deformed into a hill-like shape, or where a barrier to migration has occurred by earth (tectonic) movement to create a similar trapping mechanism, oil and gas will build up. These are called structural traps. If the gas is not entirely dissolved in the oil, it will form a ‘gas cap’ layer on top of the oil. As long as the source continues to generate hydrocarbons and the migration pathway remains open, this build-up occurs until the trap is full with hydrocarbons, and any further migration spills (at the ‘spill point’) laterally to find a new path upwards. View largeDownload slide View largeDownload slide Conventional traps can also occur when the composition of rock in a layer changes laterally. This may be as a result of natural deposition of ever-finer particles further away from the depositional source, or as a result of chemical deposition or alteration of the rocks. These may then form ‘stratigraphic’ traps. Unconventional hydrocarbon deposits are an extension of the stratigraphic trap concept. In the case of tight oil or gas, or shale oil5 or gas, the rock quality is such that not all hydrocarbons have been able to migrate away, and are retained within the overall fabric (sometimes referred to as the ‘matrix’) of the rock.6 Tar sands and similar very heavy oil are trapped by their very high viscosity, too high to allow them to flow naturally so they remain trapped where they accumulated. In unconventional tight or shale exploitation, the permeability needed to allow the oil or gas to flow is created artificially by hydraulic fracturing (fracking), a process that creates fissures in the rock that then allows hydrocarbons to flow to the wellbore. In tar sands the sand is either mined or, where deeper, heated to reduce its viscosity until it is capable of flowing into a wellbore. View largeDownload slide View largeDownload slide The volumes reported as oil and gas reserves and resources are different from the volumes that exist in the reservoir. The production of hydrocarbons changes physical conditions in the reservoir. What may start as gas dissolved in oil in the reservoir may, over time and with declining pressure in the reservoir, become a separate ‘cap’ of free gas with further gas remaining dissolved in the oil. Some reservoirs may start out in this condition, and some may start out purely as gas. Just as changing conditions in the reservoir change the composition of the hydrocarbon fluid contained therein, so does the act of producing the hydrocarbons. As the fluid at reservoir conditions proceeds up the wellbore to surface, pressure and temperature reduce and gas separates from oil. At surface conditions pressure is typically lowered further still to allow for transfer to storage or pipelines, and more gas and gas liquids are released. Gas liquids are commonly referred to as Natural Gas Liquids,7 or NGLs, and may be reported as separate volumes in reserves reports.8 Most reservoirs referred to as ‘gas’ actually produce some volume of NGLs as well. This separation of gas from oil, and NGLs from gas, reduces the original volume from which they were derived. Thus, for example, reporting NGLs separately from gas will reduce the volume of gas that is reported although the value of the components will (or should be) higher. Estimating and reporting those volumes is undertaken by a number of well-established techniques, although they all have one common challenge. Oil and gas in the ground cannot be measured directly (like dipping a tank). That measurement must be undertaken by indirect means, and results inferred from those. While those measuring techniques have improved significantly over the years, and will undoubtedly improve further in years to come, the fact of indirect measurement and inference means that any estimates have a limit to their accuracy, which in turn can give rise to reasonable differences and dispute. Understanding this point is important when reading and assessing assertions as to volumes and value. Quantifying hydrocarbon volumes There are two essential steps in the quantification of hydrocarbon volumes: Assessing the volume of hydrocarbons in the ground. Assessing the volume of those hydrocarbons that can be recovered or, in the case of a field or well already producing, that remains to be recovered. While both steps must be undertaken, ultimately the only number that counts is the volume that not only can be recovered, but that can be recovered economically. Assessing the volumes of hydrocarbons in the ground As noted above, there are well-established techniques by which volume estimation takes place. This involves indirect measuring techniques such as seismic and well logs, the creation of geological models to represent the nature of the subsurface in and around the accumulation, and interpretation of data (particularly of production volume and pressure) to benchmark that model and forecast future production. The interpretation of seismic information is the primary geophysical technique used to ‘map’ the subsurface and delineate the size and shape of the reservoir that contains, or may contain, the oil and gas. Mapping is much the same process as geographers use for mapping the topography of an area, but in this case the expressions (hills, mountains, etc.) one can see on the surface are inferred from seismic information. ‘Seismic’ information is basically a record of how fast energy (in the form of sound waves) travels through and reflects from different layers or strata of rock in the subsurface. The maps result from a consolidation of a very large volume of data (as both the source of the energy and the sensors that measure the reflections are moved across an area). These maps are referred to as ‘time’ maps since they are measuring the time it takes for the energy to travel through the rocks. View largeDownload slide View largeDownload slide The time maps are then converted9 to ‘depth’ maps, which are directly analogous to the contours on a topographic map. The crest of a structure can be in different locations on time and depth maps. Volumetric estimates of hydrocarbons initially in place (ie before the start of production) are based on a model that geometrically describes the reservoir. As oil and gas are trapped in the pore spaces within the rock, it is necessary to identify the following: Gross Rock Volume (GRV). The area of rock that contains established or potentially producible hydrocarbons (gas and/or oil), and its thickness, is taken from the maps of the subsurface and identifying the area of the map that contains, or potentially contains, producible hydrocarbons. Finally, the limits of the area and thickness defined to be hydrocarbon-bearing (or potentially hydrocarbon-bearing) exclude areal and vertical portions of the reservoir that contain or are thought to contain or produce only water, and/or are estimated to be of too low permeability to produce hydrocarbons. Porosity (Ø). The fraction of the rock that can contain fluids (oil, gas and water). This parameter represents the pore space of the rock and is obtained by analysis of well logs and core10 samples. Where there are no actual well data, such as for undrilled prospects, values are taken from analogous fields or reservoirs, or regional basin trends where such data exist. Average net hydrocarbon thickness (Net to Gross Ratio, NGR). While a reservoir rock may be estimated from seismic or, better still, well data to be of a particular gross thickness, not all of this rock will necessarily be of reservoir quality. It is necessary to estimate the average thickness of the reservoir rock that contains hydrocarbons, and is sufficiently permeable to allow the hydrocarbons to be produced. This information is obtained from the combination of petrophysical analysis of well logs11 including the porosity measurements and, where available, from well test results. Hydrocarbon saturation (‘Sg’ for gas, ‘So’ for oil). The fraction of the pore space that is occupied by hydrocarbons (the remainder is occupied by water). This parameter is also obtained by analysis of well logs. Formation volume factor (‘Bg’ for gas, ‘Bo’ for oil). As noted above, the volume of oil and gas in the reservoir is different from that which is obtained at the surface and is available for sale. Gas expands as it comes to the surface, while oil shrinks as gas comes out of solution. These factors are derived from the pressure and temperature in the reservoir and the properties of the gas and/or oil. The volumetric equation for hydrocarbons initially in place is then:12 Hydrocarbons initially in place=GRV*NGR*Ø*Sh/Bh. Assessing the volumes of recoverable hydrocarbons Techniques to assess volumes of recoverable hydrocarbons are a function of the level of maturity/state of development of the reservoir or field. For exploration prospects, estimates will be made of the recovery factor13 using analogues for the fluid and type of reservoir expected. The more certain the analogues (nearby fields or reservoirs in well-established plays), the greater the confidence in the recovery factor to be used. For discoveries, the approach taken may vary by the nature of the discovery, in particular how close the Contract rightsholders are to considering development. At one end of the spectrum the approach of using analogues will be applied, as for exploration prospects or potential. At the other end, where a significant development is being contemplated and prior to a final investment decision (FID) being made, a geological model will be prepared and the expected production from different development options will be simulated.14 This will allow (in combination with cash flow analysis) the selection of a preferred development plan, and optimization of well placements and timing. For fields and wells already on production, there are additional approaches that use production and pressure data collected over time to ‘history match’ and back-check starting assumptions, and estimate remaining recovery. The two main methods used are ‘material balance’ (of which dynamic reservoir simulation is a more complex form), and ‘decline curve analysis’ (also known as ‘DCA’). Material balance analysis is an interpretation method using industry-standard equations to derive estimates of hydrocarbons originally in place based on historical production, static pressure data and reservoir fluid properties. It is independent of the volumetric analysis, and can be used to provide additional confidence in the volume of hydrocarbons in place. For gas fields, the material balance approach can be relatively simple. Reservoir pressure15 is plotted against cumulative gas production (known as ‘p/z’) and, as long as there is no other source of reservoir energy (such as water influx or reservoir compaction), the data will plot as a straight line. This is then extrapolated to zero pressure to derive the gas initially in place. However, not all gas estimated to exist in the reservoir can be recovered, so the ultimate recovery is assessed based on the evaluated reservoir abandonment pressure (ie the pressure at which a well or group of wells will stop flowing or will be shut in). This will depend on a number of factors including rock properties, surface facility conditions (including whether there are any compressors to boost surface pressure) and economics. This is illustrated in the example below where declining pressure readings over the first 21 Bscf of production indicate a GIIP of 150 Bscf. At the expected abandonment pressure a total of 140 Bscf will have been produced,16 leaving 119 Bscf remaining to be produced (the ‘reserves’ in this case). View largeDownload slide View largeDownload slide Unfortunately, many reservoirs or wells are not as simple as the example, and do have water influx or rock compression.17 This makes the interpretation more complex and without making interpretive corrections it will over-estimate the GIIP.18 Material balance analysis may also be used for oil reservoirs, although it is rather more complicated due to the more complex behaviour of oil with its dissolved gas in the reservoir. The second method of performance analysis is DCA. This technique is based on the expectation that the factors that control a well’s (or a group of wells’) performance in the past will continue to control production into the future. It has been established as a reliable tool for analysis, used for at least the past 70 years. While a number of different formulations19 are currently in use, the most common is termed ‘exponential decline’. It has been found that the rate of production from certain types of reservoirs, when plotted on a logarithmic scale against time, will follow a straight line. Since straight lines are simple to extrapolate, once again the evaluator can have confidence that the prediction is reasonable. The extrapolation is continued to the economic limit (the point in time at which the revenue projected to be obtained from the sale of hydrocarbon production becomes equal to the projected cost to operate—see discussion in cash flow section) for the well or group of wells being analysed. View largeDownload slide View largeDownload slide Production data is rarely that straightforward to interpret, as changing conditions in a field’s or a well’s production life will cause production to vary over time even when exhibiting an overall decline trend. Further, looking at the overall production decline in a field, as opposed to the individual wells in that field, will produce a somewhat different outcome because the overall field decline smooths out the impact of variability in individual wells caused by workovers and operational changes, for instance. These uncertainties are then translated into estimates of EUR at different confidence levels, themselves supporting reserves categories when the additional planning and economic factors are taken into account. Classifying the hydrocarbon volumes (reserves and resources20) While there are a number of different standards around the world for the classification of hydrocarbon volumes, most international oil and gas companies either recognize or adhere to a set of standards known as the Petroleum Resources Management System, or PRMS. Other standards are adopted, particularly when reporting under different regulations, but with the exception of the former Soviet system (for example) the principles involved are very similar. A detailed description and comparison of these standards goes beyond this article; however, links to the PRMS, SEC and Canadian NI 51-101 definitions are provided in the footnote below.21 Except where noted otherwise, PRMS standards are discussed in this article. Classification is important because it separates volumes into three major classes, with each class representing a major change in risk type (which in turn affects the valuation). ‘Reserves’ are (volume for volume) the most important because they represent a quantification of expected future production from discoveries that are either producing, under development, or committed for development. Key attributes of reserves also include the fact that they must be remaining,22 economic, and be subject to a plan of development.23 The last point is important to understand in the context of partial development of a discovery; only those hydrocarbons expected to be recovered by the part being developed can be classified as reserves. ‘Contingent Resources’ represent hydrocarbons that have been discovered, but where a development is not yet sufficiently certain (including, to follow from the point above, parts of a field that are not yet reasonably certain to be developed).24 The chance of development may be quite high if sufficient work has been done to be able to evaluate the discovery and to define a viable development plan, but various approvals are still pending. On the other hand, the chance of development may be low if, despite a lot of work, the discovery does not look promising and it looks unlikely to be developed (at least in the near term). In practice, Contingent Resources represents a spectrum of discoveries between the two. ‘Prospective Resources’ (or, as frequently referred to, ‘Exploration Upside’ or ‘Exploration Potential’) are distinguished from Reserves and Contingent Resources by the fact that they may not exist at all. They have yet to be discovered. While indirect measuring techniques, such as seismic, have improved enormously over the years and may provide very high confidence as to the presence of hydrocarbons, the use of seismic is not yet accepted as proof of a discovery. That requires proving the presence using the drill bit, and it remains true that more exploration wells fail to find the hoped-for hydrocarbons than succeed. Within each of these major classifications are categories that are used to assign confidence to the recovery estimates. Reserves are categorized as ‘Proved’, ‘Probable’ or ‘Possible’, representing different confidence levels with respect to the future recovery of those volumes. The use of each of these categories in valuation is discussed further in Part II of this article, and further in respect of the actual categorization process, further below. While each of the Reserves, Contingent Resources and Prospective Resources classifications has sub-classes, these are less commonly utilized other than by influencing risk factors to be applied in adjusting cash flows, and are not discussed further in this article. The totality of relationships is best summed up in the following chart taken from the PRMS. View largeDownload slide View largeDownload slide Reserves categories Reserves are divided into three categories, and a further number of sub-categories. The best known are Proved, Probable and Possible categories which are often reported (along with their abbreviations) in aggregated quantities—Proved (1P), Proved plus Probable (2P) and Proved plus Probable plus Possible (3P).25 Further status qualifiers divide these into ‘Developed’ (all the major capital has already been spent and the only future costs that remain are for operating a field/well, and minor workovers) and ‘Undeveloped’. While Developed and Undeveloped can be applied to each of the main categories, they are most commonly only applied to Proved, notably as Proved Developed (PD) and Proved Undeveloped (PUD). Proved Developed may be further divided into Producing (PDP) and Not Producing (PDNP), the difference being that the latter is awaiting an intervention (typically a workover, but perhaps also some surface facility changes). All of the above reflect different confidence levels for future recovery. The first level of segregation is between 1P, 2P and 3P. There are slight differences in definition between SEC and PRMS although, the use of oil or gas prices aside, these are usually not material. 1P reserves are those volumes in which there is reasonable certainty of future recovery. As noted elsewhere, there is no absolute definition of ‘reasonable certainty’, although PRMS defines this where probabilistic methods have been used to estimate reserves as there being a 90 per cent chance that this volume, or more, will ultimately be recovered.26 2P reserves assumes a 50 per cent chance (there being an equal probability that the volume ultimately produced will fall short of, or exceed, this volume), and 3P reserves assumes a 10 per cent chance of exceeding (and a 90 per cent chance of falling short).27 While confidence levels are assigned to 1P, 2P and 3P (if they are evaluated probabilistically), they are not similarly assigned to Developed and Undeveloped even though intuitively there would always be greater confidence in a Developed rather than an Undeveloped volume. Industry players may independently adjust values to reflect such differences, but there is no formal standard as there is for reserves categories. However, the process of categorizing volumes will incorporate this confidence differentiation through the uncertainty range involved in estimating future production and recovery. Undeveloped reserves volumes will tend to exhibit a wider range of uncertainty, causing a greater proportion of the volume to be attributed to the Probable and/or Possible categories than is likely to be the case with reserves estimates for producing volumes. It is most common in the USA to deal only with 1P reserves (for historical reasons, but also because that category is all that is required to be reported to the SEC), although for the rest of the world while 1P and 2P (and occasionally 3P) are reported, the most common standard for use in valuations and public announcements is 2P, which is synonymous with a ‘best estimate’. The implications for valuation of the use of different reserves categories, and developed and undeveloped categories, are dealt with further in Part II of this article. There are other aspects to the process of reserves evaluation which for valuation purposes it may be useful to understand: Incremental (or Step-out) approach. In the USA, particularly onshore, historical practice has been to handle the categorization of reserves categories by ‘step-out locations’. In simplified terms, one step-out location is the next-nearest well that would be drilled to an existing well.28 Under such an approach Proved reserves are assigned to wells one step-out location away in order to provide the necessary high degree of confidence in both the presence and producibility of the reservoir. Although not always done, operators might elect to assign Probable reserves to locations two step-outs away and Possible to three. However, there are no definitions that actually limit this and, depending on the amount of data and analogues, Proved Undeveloped locations could be assigned up to two step-out locations from an existing well if data supported that, Probable to three or four, and Possible to four or more. While the number of conventional onshore oil and gas developments (and the volume of associated reserves) has been declining, the advent of unconventional developments has brought the need for understanding on this issue back into focus. Whereas conventional onshore developments might have only covered a relatively small and finite area, limiting the number of drilling locations possible, unconventional developments are by their very nature areally very extensive and it may be possible to contemplate hundreds or thousands of potential future locations. Thus, from a technical perspective it may be possible to contemplate many years of future drilling activity with a broad spread of locations in each of the reserves categories. While such thinking may have been appropriate in the past, and still has some resonance today based on the intuitive appeal of being technically confident in the ability to recover hydrocarbons, it is insufficient to justify categorization as reserves. As noted above, in order to classify hydrocarbons as reserves there has to be reasonable expectation that the activity necessary (wells and facilities) will be undertaken. In many cases, evidence for this is the presence of a final investment decision to spend the money in question.29 When the activities required would take many years to fulfil the question arises as to whether the ‘reasonable expectation’ of development exists; not ‘at some time’, but in line with the business plan and economic model demonstrating the commerciality of the activity. As is discussed in Part II of the article, the impact of this issue became apparent in the most recent price downturn in 2014. Cumulative (or scenario) approach. In many parts of the world, and particularly in offshore environments, a different approach is used. That contemplates reserves not based on step-out locations, but on the total recovery from the field, or the part of the field subject to development. 1P, 2P and 3P reserves (equivalent to low, best and high estimates30) are then assigned to recovery from the complete field, incorporating uncertainty as to reservoir parameters, field limits and recovery efficiency. Frequently this is undertaken though static and dynamic reservoir modelling and simulation, although less intense and traditional mapping approaches can also yield the same result. There is no evidence to support either of these two approaches being systematically better than the other. The step-out approach fits better in the USA where leases tend to be small and a field may be subject to many leases operated by different parties. Over-depletion over a field is managed through State regulations on the spacing of wells. Outside of the USA, leases are typically much larger and fields often smaller than the lease, such that the Contract rightsholder will typically have to submit (and have approved) a plan of development covering the entire field. Probabilistic approach. Independent of any of the approaches to assessing reserves or resources, some evaluators prefer to use a probabilistic approach. This deals with the uncertainties surrounding all the parameters that go into the estimation and uses Monte Carlo31 simulation to produce a range from which estimates of probability of recovery can be assigned. The advantages of this approach are that it can take into account a much greater range of uncertainties than can a deterministic approach, and provide a clearer vision of not just the range of results, but the distribution of outcomes within that range. One disadvantage is that there is no clear determination of the particular combination of parameters that gave rise to the P90 estimate such that it can be demonstrated that the constraints32 for Proved reserves have been met. Further, defining dependencies between variables can be extremely difficult and may result in combinations of outcomes that in reality may be impossible or exceedingly unlikely. Deterministic approach. This is the traditional approach to reserves and resource estimation, whereby limits are placed on key parameters for each confidence level. Thus, for example, Proved Reserves will be limited by the most conservative interpretation of the limits of the accumulation, by not extrapolating beyond the depth of oil and gas already seen in wells even when it is known that these are not the absolute limits, and so forth. It is favoured where people like to be clear as to exactly what parameters define any particular confidence level in a reserve or resource category. As with the incremental/step-out and cumulative/scenario approaches, there is no evidence of systematic bias in results one way or another. While the deterministic approach is the approach used in incremental/step-out, it can also be used in the cumulative/scenario approach. Should probabilities be required for subsequent use, 90 per cent, 50 per cent and 10 per cent probabilities can be assigned to the 1P, 2P and 3P categories even though these were not derived in a probabilistic manner. Building a cash flow Reserves and resources have value through being monetized. In order to measure this value the most common practice is to build a cash flow model (although, as discussed in Part II of this article, other metrics may be applied directly to assess value when the cash flow option is not capable of being applied). That model will play out over time the production of hydrocarbons, assume a price for at which each of the hydrocarbon streams will be sold to achieve a revenue forecast, and deduct from this the cost of being able to make those sales. Those costs comprise two parts. The first of these is the investments (where the assets have still be developed, in whole or part), and the operating costs to produce the hydrocarbons. The second is the various contractual or fiscal deductions that are applicable. These would include (but not necessarily be limited to) government and landowner royalties, licence fees and other social or land use taxes, special petroleum taxes, sharing of production with the state (where the applicable Petroleum Contract calls for that), and income taxes. Having built the model, the future net cash flow to the Contract rightsholder is what is being valued, adjusting the monthly or annual forecasts back to a present value using an appropriate discount rate. The choice of discount rate, and various issues surrounding this choice, are discussed in Part II of this article. The cash flow and discounting process is often referred to as the Discounted Cash Flow, or DCF, and the discounted result as the Net Present Value, or NPV. NPVs are always quoted with their discount rate and as of a specified date. Changing the date will change the NPV not just because of the effect of time in discounting the cash flow, but potentially as well because of the impact the date could have on the state of knowledge as of the changed date.33 For example, in cases where what is known or knowable as of a certain date is important, changing a discount date to before or after the results of a well that modifies significantly the understanding of a field, or where there is a material change in market perception as to future oil prices (such as occurred in 2014), would have a major impact on NPV. An example cash flow is shown below, annotated to illustrate some of the key features. There is no standard format for cash flows, and each valuer or organization tends to use their own model and standards. The first step is to model the forecast production (from the reserves or resources, as applicable to the case being modelled), and calculate expected sales revenues. Where companies have a partial interest in a Petroleum Contract, their interests are shown as Working Interest (the proportion of overall costs that are paid) and Revenue Interest (the proportion of production or revenue to which they are entitled). Depending on the contract, the Working Interest and Revenue Interest may be the same, or different.34 To obtain sales revenues involves assuming future oil and gas prices (and the prices for any other products, such as natural gas liquids), and multiplying these to calculate the revenue that would be expected from those volumes and those prices.35 Production is assumed to continue until either the Petroleum Contract terminates, or until the production costs exceed the revenue. As will be discussed in Part II, production profiles that constitute reserves should automatically have had their production profiles truncated at one of these two points (or they would have violated conditions that allow them to be called reserves). However, when running a cash flow for valuation purposes the oil and gas price assumptions may be different to those used for reserves, and/or other assumptions may be made with respect to Petroleum Contract duration, in either case extending or shortening the life of the profile. Example cash flow showing derivation of gross revenue Global oil and gas company Prospective Acquisition Asset Working Interest: 50.00% Revenue Interest: 50.00% Production Price Revenue Brent Oil Realized Oil Gas Oil Gas Gross Oil Gas Price Price Price Revenue Revenue Revenue Bopd Mscfd $/Bbl $/Bbl $/Mcf $M $M $M Total/Boe 9,633,528 66.18 57.82 3.60 57.82 3.60 35.73 2018 1044 9517 60.00 54.00 3.35 20,597 11,635 32,233 2019 2065 17,208 60.90 54.81 3.38 41,338 21,268 62,606 2020 1418 13,328 61.81 55.63 3.43 28,816 16,697 45,513 2021 1145 10,825 62.74 56.47 3.49 23,624 13,782 37,406 2022 920 8514 63.68 57.31 3.54 19,265 10,994 30,259 2023 681 6353 64.64 58.17 3.57 14,477 8293 22,770 2024 519 4805 65.61 59.05 3.61 11,202 6341 17,542 2025 434 3860 66.59 59.93 3.66 9506 5165 14,672 2026 365 3208 67.59 60.83 3.72 8099 4359 12,458 2027 307 2759 68.60 61.74 3.79 6924 3815 10,739 S/T (Bbls/Mscf) 3,250,585 29,357,756 62.84 56.56 3.49 183,848 102,349 286,197 Remainder 507,963 5,892,127 74.30 65.88 4.17 33,466 24,552 58,017 Total 3,758,548 35,249,883 66.18 57.82 3.60 217,314 126,901 344,215 Global oil and gas company Prospective Acquisition Asset Working Interest: 50.00% Revenue Interest: 50.00% Production Price Revenue Brent Oil Realized Oil Gas Oil Gas Gross Oil Gas Price Price Price Revenue Revenue Revenue Bopd Mscfd $/Bbl $/Bbl $/Mcf $M $M $M Total/Boe 9,633,528 66.18 57.82 3.60 57.82 3.60 35.73 2018 1044 9517 60.00 54.00 3.35 20,597 11,635 32,233 2019 2065 17,208 60.90 54.81 3.38 41,338 21,268 62,606 2020 1418 13,328 61.81 55.63 3.43 28,816 16,697 45,513 2021 1145 10,825 62.74 56.47 3.49 23,624 13,782 37,406 2022 920 8514 63.68 57.31 3.54 19,265 10,994 30,259 2023 681 6353 64.64 58.17 3.57 14,477 8293 22,770 2024 519 4805 65.61 59.05 3.61 11,202 6341 17,542 2025 434 3860 66.59 59.93 3.66 9506 5165 14,672 2026 365 3208 67.59 60.83 3.72 8099 4359 12,458 2027 307 2759 68.60 61.74 3.79 6924 3815 10,739 S/T (Bbls/Mscf) 3,250,585 29,357,756 62.84 56.56 3.49 183,848 102,349 286,197 Remainder 507,963 5,892,127 74.30 65.88 4.17 33,466 24,552 58,017 Total 3,758,548 35,249,883 66.18 57.82 3.60 217,314 126,901 344,215 Last month production: Jan-41. View Large Example cash flow showing derivation of gross revenue Global oil and gas company Prospective Acquisition Asset Working Interest: 50.00% Revenue Interest: 50.00% Production Price Revenue Brent Oil Realized Oil Gas Oil Gas Gross Oil Gas Price Price Price Revenue Revenue Revenue Bopd Mscfd $/Bbl $/Bbl $/Mcf $M $M $M Total/Boe 9,633,528 66.18 57.82 3.60 57.82 3.60 35.73 2018 1044 9517 60.00 54.00 3.35 20,597 11,635 32,233 2019 2065 17,208 60.90 54.81 3.38 41,338 21,268 62,606 2020 1418 13,328 61.81 55.63 3.43 28,816 16,697 45,513 2021 1145 10,825 62.74 56.47 3.49 23,624 13,782 37,406 2022 920 8514 63.68 57.31 3.54 19,265 10,994 30,259 2023 681 6353 64.64 58.17 3.57 14,477 8293 22,770 2024 519 4805 65.61 59.05 3.61 11,202 6341 17,542 2025 434 3860 66.59 59.93 3.66 9506 5165 14,672 2026 365 3208 67.59 60.83 3.72 8099 4359 12,458 2027 307 2759 68.60 61.74 3.79 6924 3815 10,739 S/T (Bbls/Mscf) 3,250,585 29,357,756 62.84 56.56 3.49 183,848 102,349 286,197 Remainder 507,963 5,892,127 74.30 65.88 4.17 33,466 24,552 58,017 Total 3,758,548 35,249,883 66.18 57.82 3.60 217,314 126,901 344,215 Global oil and gas company Prospective Acquisition Asset Working Interest: 50.00% Revenue Interest: 50.00% Production Price Revenue Brent Oil Realized Oil Gas Oil Gas Gross Oil Gas Price Price Price Revenue Revenue Revenue Bopd Mscfd $/Bbl $/Bbl $/Mcf $M $M $M Total/Boe 9,633,528 66.18 57.82 3.60 57.82 3.60 35.73 2018 1044 9517 60.00 54.00 3.35 20,597 11,635 32,233 2019 2065 17,208 60.90 54.81 3.38 41,338 21,268 62,606 2020 1418 13,328 61.81 55.63 3.43 28,816 16,697 45,513 2021 1145 10,825 62.74 56.47 3.49 23,624 13,782 37,406 2022 920 8514 63.68 57.31 3.54 19,265 10,994 30,259 2023 681 6353 64.64 58.17 3.57 14,477 8293 22,770 2024 519 4805 65.61 59.05 3.61 11,202 6341 17,542 2025 434 3860 66.59 59.93 3.66 9506 5165 14,672 2026 365 3208 67.59 60.83 3.72 8099 4359 12,458 2027 307 2759 68.60 61.74 3.79 6924 3815 10,739 S/T (Bbls/Mscf) 3,250,585 29,357,756 62.84 56.56 3.49 183,848 102,349 286,197 Remainder 507,963 5,892,127 74.30 65.88 4.17 33,466 24,552 58,017 Total 3,758,548 35,249,883 66.18 57.82 3.60 217,314 126,901 344,215 Last month production: Jan-41. View Large In the example above, royalty (if payable) is treated as a fiscal deduction from Gross Revenue, as would be the treatment for production or special petroleum taxes; depending on jurisdiction and whether a government or private royalty the revenue recognized for this may vary slightly, typically through the effective definition of the sales point and value there. Example royalty payable where royalty is treated as a fiscal deduction Gross Oil Gas Total Net revenue royalty royalty royalty revenue $M $M $M $M $M Total/Boe 35.73 12.78 3.64 7.20 28.53 2018 32,233 4444 1924 6368 25,865 2019 62,606 8962 3526 12,488 50,118 2020 45,513 6278 2776 9055 36,458 2021 37,406 5173 2300 7473 29,933 2022 30,259 4240 1840 6080 24,179 2023 22,770 3202 1392 4594 18,176 2024 17,542 2491 1067 3558 13,985 2025 14,672 2125 872 2997 11,675 2026 12,458 1820 739 2558 9900 2027 10,739 1564 649 2213 8526 S/T (Bbls/Mscf) 286,197 40,299 17,085 57,383 228,814 Remainder 58,017 7,746 4,275 12,022 45,996 Total 344,215 48,045 21,360 69,405 274,810 Gross Oil Gas Total Net revenue royalty royalty royalty revenue $M $M $M $M $M Total/Boe 35.73 12.78 3.64 7.20 28.53 2018 32,233 4444 1924 6368 25,865 2019 62,606 8962 3526 12,488 50,118 2020 45,513 6278 2776 9055 36,458 2021 37,406 5173 2300 7473 29,933 2022 30,259 4240 1840 6080 24,179 2023 22,770 3202 1392 4594 18,176 2024 17,542 2491 1067 3558 13,985 2025 14,672 2125 872 2997 11,675 2026 12,458 1820 739 2558 9900 2027 10,739 1564 649 2213 8526 S/T (Bbls/Mscf) 286,197 40,299 17,085 57,383 228,814 Remainder 58,017 7,746 4,275 12,022 45,996 Total 344,215 48,045 21,360 69,405 274,810 View Large Example royalty payable where royalty is treated as a fiscal deduction Gross Oil Gas Total Net revenue royalty royalty royalty revenue $M $M $M $M $M Total/Boe 35.73 12.78 3.64 7.20 28.53 2018 32,233 4444 1924 6368 25,865 2019 62,606 8962 3526 12,488 50,118 2020 45,513 6278 2776 9055 36,458 2021 37,406 5173 2300 7473 29,933 2022 30,259 4240 1840 6080 24,179 2023 22,770 3202 1392 4594 18,176 2024 17,542 2491 1067 3558 13,985 2025 14,672 2125 872 2997 11,675 2026 12,458 1820 739 2558 9900 2027 10,739 1564 649 2213 8526 S/T (Bbls/Mscf) 286,197 40,299 17,085 57,383 228,814 Remainder 58,017 7,746 4,275 12,022 45,996 Total 344,215 48,045 21,360 69,405 274,810 Gross Oil Gas Total Net revenue royalty royalty royalty revenue $M $M $M $M $M Total/Boe 35.73 12.78 3.64 7.20 28.53 2018 32,233 4444 1924 6368 25,865 2019 62,606 8962 3526 12,488 50,118 2020 45,513 6278 2776 9055 36,458 2021 37,406 5173 2300 7473 29,933 2022 30,259 4240 1840 6080 24,179 2023 22,770 3202 1392 4594 18,176 2024 17,542 2491 1067 3558 13,985 2025 14,672 2125 872 2997 11,675 2026 12,458 1820 739 2558 9900 2027 10,739 1564 649 2213 8526 S/T (Bbls/Mscf) 286,197 40,299 17,085 57,383 228,814 Remainder 58,017 7,746 4,275 12,022 45,996 Total 344,215 48,045 21,360 69,405 274,810 View Large Further, unless ‘only’ payable in cash, most reporting standards deduct royalty as a volume belonging to the royalty owner (known as Royalty In Kind), reporting as reserves to the Contract rightsholder only the net volume. From a cash flow perspective, the result (the Net Revenue number in this case) is the same although if this issue is not fully appreciated it can be confusing because of the two different volumes represented. Example where royalty is taken in kind Production Price Revenue Brent Oil Realized Oil Gas Oil Gas Gross Net Oil Gas Price Price Price Revenue Revenue Revenue Revenue Bopd Mscfd $/Bbl $/Bbl $/Mcf $M $M $M $M Total/Boe 7,813,679 64.24 57.82 3.60 57.82 3.60 35.17 35.17 2018 819 7943 60.00 54.00 3.35 16,154 9711 25,865 25,865 2019 1617 14,355 60.90 54.81 3.38 32,376 17,742 50,118 50,118 2020 1109 11,112 61.81 55.63 3.43 22,538 13,920 36,458 36,458 2021 895 9018 62.74 56.47 3.49 18,451 11,482 29,933 29,933 2022 718 7089 63.68 57.31 3.54 15,025 9154 24,179 24,179 2023 531 5287 64.64 58.17 3.57 11,275 6901 18,176 18,176 2024 404 3996 65.61 59.05 3.61 8711 5274 13,985 13,985 2025 337 3209 66.59 59.93 3.66 7382 4293 11,675 11,675 2026 283 2664 67.59 60.83 3.72 6279 3621 9900 9900 2027 238 2290 68.60 61.74 3.79 5360 3166 8526 8526 S/T (Bbls/Mscf) 2,538,409 24,457,180 62.83 56.55 3.49 143,550 85,264 228,814 228,814 Remainder 389,179 4,866,060 73.43 66.09 4.17 25,719 20,276 45,996 45,996 Total 2,927,588 29,316,546 64.24 57.82 3.60 169,269 105,540 274,810 274,810 Production Price Revenue Brent Oil Realized Oil Gas Oil Gas Gross Net Oil Gas Price Price Price Revenue Revenue Revenue Revenue Bopd Mscfd $/Bbl $/Bbl $/Mcf $M $M $M $M Total/Boe 7,813,679 64.24 57.82 3.60 57.82 3.60 35.17 35.17 2018 819 7943 60.00 54.00 3.35 16,154 9711 25,865 25,865 2019 1617 14,355 60.90 54.81 3.38 32,376 17,742 50,118 50,118 2020 1109 11,112 61.81 55.63 3.43 22,538 13,920 36,458 36,458 2021 895 9018 62.74 56.47 3.49 18,451 11,482 29,933 29,933 2022 718 7089 63.68 57.31 3.54 15,025 9154 24,179 24,179 2023 531 5287 64.64 58.17 3.57 11,275 6901 18,176 18,176 2024 404 3996 65.61 59.05 3.61 8711 5274 13,985 13,985 2025 337 3209 66.59 59.93 3.66 7382 4293 11,675 11,675 2026 283 2664 67.59 60.83 3.72 6279 3621 9900 9900 2027 238 2290 68.60 61.74 3.79 5360 3166 8526 8526 S/T (Bbls/Mscf) 2,538,409 24,457,180 62.83 56.55 3.49 143,550 85,264 228,814 228,814 Remainder 389,179 4,866,060 73.43 66.09 4.17 25,719 20,276 45,996 45,996 Total 2,927,588 29,316,546 64.24 57.82 3.60 169,269 105,540 274,810 274,810 Last month production: Jan-41. View Large Example where royalty is taken in kind Production Price Revenue Brent Oil Realized Oil Gas Oil Gas Gross Net Oil Gas Price Price Price Revenue Revenue Revenue Revenue Bopd Mscfd $/Bbl $/Bbl $/Mcf $M $M $M $M Total/Boe 7,813,679 64.24 57.82 3.60 57.82 3.60 35.17 35.17 2018 819 7943 60.00 54.00 3.35 16,154 9711 25,865 25,865 2019 1617 14,355 60.90 54.81 3.38 32,376 17,742 50,118 50,118 2020 1109 11,112 61.81 55.63 3.43 22,538 13,920 36,458 36,458 2021 895 9018 62.74 56.47 3.49 18,451 11,482 29,933 29,933 2022 718 7089 63.68 57.31 3.54 15,025 9154 24,179 24,179 2023 531 5287 64.64 58.17 3.57 11,275 6901 18,176 18,176 2024 404 3996 65.61 59.05 3.61 8711 5274 13,985 13,985 2025 337 3209 66.59 59.93 3.66 7382 4293 11,675 11,675 2026 283 2664 67.59 60.83 3.72 6279 3621 9900 9900 2027 238 2290 68.60 61.74 3.79 5360 3166 8526 8526 S/T (Bbls/Mscf) 2,538,409 24,457,180 62.83 56.55 3.49 143,550 85,264 228,814 228,814 Remainder 389,179 4,866,060 73.43 66.09 4.17 25,719 20,276 45,996 45,996 Total 2,927,588 29,316,546 64.24 57.82 3.60 169,269 105,540 274,810 274,810 Production Price Revenue Brent Oil Realized Oil Gas Oil Gas Gross Net Oil Gas Price Price Price Revenue Revenue Revenue Revenue Bopd Mscfd $/Bbl $/Bbl $/Mcf $M $M $M $M Total/Boe 7,813,679 64.24 57.82 3.60 57.82 3.60 35.17 35.17 2018 819 7943 60.00 54.00 3.35 16,154 9711 25,865 25,865 2019 1617 14,355 60.90 54.81 3.38 32,376 17,742 50,118 50,118 2020 1109 11,112 61.81 55.63 3.43 22,538 13,920 36,458 36,458 2021 895 9018 62.74 56.47 3.49 18,451 11,482 29,933 29,933 2022 718 7089 63.68 57.31 3.54 15,025 9154 24,179 24,179 2023 531 5287 64.64 58.17 3.57 11,275 6901 18,176 18,176 2024 404 3996 65.61 59.05 3.61 8711 5274 13,985 13,985 2025 337 3209 66.59 59.93 3.66 7382 4293 11,675 11,675 2026 283 2664 67.59 60.83 3.72 6279 3621 9900 9900 2027 238 2290 68.60 61.74 3.79 5360 3166 8526 8526 S/T (Bbls/Mscf) 2,538,409 24,457,180 62.83 56.55 3.49 143,550 85,264 228,814 228,814 Remainder 389,179 4,866,060 73.43 66.09 4.17 25,719 20,276 45,996 45,996 Total 2,927,588 29,316,546 64.24 57.82 3.60 169,269 105,540 274,810 274,810 Last month production: Jan-41. View Large The examples shown reflect a typical tax/royalty concession style Petroleum Contract. Other contract styles may generate the revenue to the Contract rightsholder in different ways. Production Sharing Contracts will determine revenue as a combination of oil and/or gas (depending on rights) equivalent to the value of costs incurred, so-called ‘cost oil’ (with the rate of cost recovery also being controlled), plus a share of the difference between cost recovery and Gross Revenue (profit oil). Risk Service Contracts may use a mechanism similar to this, but rather than using global oil and gas prices, use a fee per barrel of oil (equivalent). Example cost and tax deductions to derive net cash flow Net Fixed Variable Total Aband Other Local Pre-Tax Income Post-Tax Revenue Capex Opex Opex Opex Fund Taxes Cash Flow Tax Cash Flow $M $M $M $M $M $M $M $M $M $M Total/Boe 35.17 1.46 2.62 1.08 3.69 0.08 1.24 22.05 6.44 15.61 2018 25,865 14,050 1080 961 2041 75 804 8895 6537 2358 2019 50,118 0 1096 1828 2925 150 1306 45,738 12,492 33,246 2020 36,458 0 1113 1369 2482 115 1033 32,828 8940 23,888 2021 29,933 0 1129 1126 2256 93 903 26,682 7269 19,413 2022 24,179 0 1146 907 2053 72 788 21,266 5782 15,483 2023 18,176 0 1163 685 1848 54 668 15,606 4224 11,381 2024 13,985 0 1181 527 1708 41 585 11,651 3173 8478 2025 11,675 0 1199 437 1635 33 538 9468 2580 6889 2026 9900 0 1217 370 1586 26 503 7784 2122 5662 2027 8526 0 1235 320 1555 22 476 6473 1765 4708 S/T (Bbls/Mscf) 228,814 14,050 11,559 8530 20,089 682 7603 186,391 54,884 131,507 Remainder 45,996 0 13,667 1834 15,501 106 4318 26,070 7159 18,911 Total 274,810 14,050 25,226 10,364 35,590 788 11,921 212,461 62,043 150,418 Net Fixed Variable Total Aband Other Local Pre-Tax Income Post-Tax Revenue Capex Opex Opex Opex Fund Taxes Cash Flow Tax Cash Flow $M $M $M $M $M $M $M $M $M $M Total/Boe 35.17 1.46 2.62 1.08 3.69 0.08 1.24 22.05 6.44 15.61 2018 25,865 14,050 1080 961 2041 75 804 8895 6537 2358 2019 50,118 0 1096 1828 2925 150 1306 45,738 12,492 33,246 2020 36,458 0 1113 1369 2482 115 1033 32,828 8940 23,888 2021 29,933 0 1129 1126 2256 93 903 26,682 7269 19,413 2022 24,179 0 1146 907 2053 72 788 21,266 5782 15,483 2023 18,176 0 1163 685 1848 54 668 15,606 4224 11,381 2024 13,985 0 1181 527 1708 41 585 11,651 3173 8478 2025 11,675 0 1199 437 1635 33 538 9468 2580 6889 2026 9900 0 1217 370 1586 26 503 7784 2122 5662 2027 8526 0 1235 320 1555 22 476 6473 1765 4708 S/T (Bbls/Mscf) 228,814 14,050 11,559 8530 20,089 682 7603 186,391 54,884 131,507 Remainder 45,996 0 13,667 1834 15,501 106 4318 26,070 7159 18,911 Total 274,810 14,050 25,226 10,364 35,590 788 11,921 212,461 62,043 150,418 View Large Example cost and tax deductions to derive net cash flow Net Fixed Variable Total Aband Other Local Pre-Tax Income Post-Tax Revenue Capex Opex Opex Opex Fund Taxes Cash Flow Tax Cash Flow $M $M $M $M $M $M $M $M $M $M Total/Boe 35.17 1.46 2.62 1.08 3.69 0.08 1.24 22.05 6.44 15.61 2018 25,865 14,050 1080 961 2041 75 804 8895 6537 2358 2019 50,118 0 1096 1828 2925 150 1306 45,738 12,492 33,246 2020 36,458 0 1113 1369 2482 115 1033 32,828 8940 23,888 2021 29,933 0 1129 1126 2256 93 903 26,682 7269 19,413 2022 24,179 0 1146 907 2053 72 788 21,266 5782 15,483 2023 18,176 0 1163 685 1848 54 668 15,606 4224 11,381 2024 13,985 0 1181 527 1708 41 585 11,651 3173 8478 2025 11,675 0 1199 437 1635 33 538 9468 2580 6889 2026 9900 0 1217 370 1586 26 503 7784 2122 5662 2027 8526 0 1235 320 1555 22 476 6473 1765 4708 S/T (Bbls/Mscf) 228,814 14,050 11,559 8530 20,089 682 7603 186,391 54,884 131,507 Remainder 45,996 0 13,667 1834 15,501 106 4318 26,070 7159 18,911 Total 274,810 14,050 25,226 10,364 35,590 788 11,921 212,461 62,043 150,418 Net Fixed Variable Total Aband Other Local Pre-Tax Income Post-Tax Revenue Capex Opex Opex Opex Fund Taxes Cash Flow Tax Cash Flow $M $M $M $M $M $M $M $M $M $M Total/Boe 35.17 1.46 2.62 1.08 3.69 0.08 1.24 22.05 6.44 15.61 2018 25,865 14,050 1080 961 2041 75 804 8895 6537 2358 2019 50,118 0 1096 1828 2925 150 1306 45,738 12,492 33,246 2020 36,458 0 1113 1369 2482 115 1033 32,828 8940 23,888 2021 29,933 0 1129 1126 2256 93 903 26,682 7269 19,413 2022 24,179 0 1146 907 2053 72 788 21,266 5782 15,483 2023 18,176 0 1163 685 1848 54 668 15,606 4224 11,381 2024 13,985 0 1181 527 1708 41 585 11,651 3173 8478 2025 11,675 0 1199 437 1635 33 538 9468 2580 6889 2026 9900 0 1217 370 1586 26 503 7784 2122 5662 2027 8526 0 1235 320 1555 22 476 6473 1765 4708 S/T (Bbls/Mscf) 228,814 14,050 11,559 8530 20,089 682 7603 186,391 54,884 131,507 Remainder 45,996 0 13,667 1834 15,501 106 4318 26,070 7159 18,911 Total 274,810 14,050 25,226 10,364 35,590 788 11,921 212,461 62,043 150,418 View Large From the Net Revenue are deducted capital and operating expenditures (fixed and variable), any contractual levies, local or petroleum taxes, and income taxes. Individual calculations are required for most of these as they have particular rules and allowances involved. Depending upon the nature of the Petroleum Contract any abandonment and site restoration costs may come at the very end, or the contract may levy these on some proportionate basis (usually based on an estimate of final costs, apportioned on a unit-of-production basis throughout the producing life of the asset). As noted above, there is a myriad of ways to model cash flow, honouring the technical analysis, the rules of reporting, and the contractual and fiscal deductions imposed. However, having prepared and verified the model of the asset in question, this then needs translating into value. The most significant step in this stage of the process is discounting the expected future cash flows at the appropriate discount rate. Issues around selecting the discount rate are addressed in Part II, but most cash flow analyses incorporate a table of Net Present Values (NPVs) at a number of different discount rates, one of which is typically the discount rate used for the valuation itself. The table can also be extended to see the value implied per unit of production at the different discount rates, which can be compared to metrics drawn from transactions in the market. This aspect is also discussed further in Part II. NPVs, and NPV/barrel equivalent, at different discount rates36 Net Present Value Unit Net Present Value At 1 January 2018 At 1 January 2018 $M $/boe Pre-Tax Post-Tax Pre-Tax Post-Tax 0% 212,461 150,418 22.05 15.61 5% 169,982 120,763 17.64 12.54 8% 151,507 107,837 15.73 11.19 10% 141,199 100,617 14.66 10.44 12.5% 130,075 92,819 13.50 9.63 15% 120,525 86,119 12.51 8.94 20% 104,990 75,207 10.90 7.81 Net Present Value Unit Net Present Value At 1 January 2018 At 1 January 2018 $M $/boe Pre-Tax Post-Tax Pre-Tax Post-Tax 0% 212,461 150,418 22.05 15.61 5% 169,982 120,763 17.64 12.54 8% 151,507 107,837 15.73 11.19 10% 141,199 100,617 14.66 10.44 12.5% 130,075 92,819 13.50 9.63 15% 120,525 86,119 12.51 8.94 20% 104,990 75,207 10.90 7.81 View Large NPVs, and NPV/barrel equivalent, at different discount rates36 Net Present Value Unit Net Present Value At 1 January 2018 At 1 January 2018 $M $/boe Pre-Tax Post-Tax Pre-Tax Post-Tax 0% 212,461 150,418 22.05 15.61 5% 169,982 120,763 17.64 12.54 8% 151,507 107,837 15.73 11.19 10% 141,199 100,617 14.66 10.44 12.5% 130,075 92,819 13.50 9.63 15% 120,525 86,119 12.51 8.94 20% 104,990 75,207 10.90 7.81 Net Present Value Unit Net Present Value At 1 January 2018 At 1 January 2018 $M $/boe Pre-Tax Post-Tax Pre-Tax Post-Tax 0% 212,461 150,418 22.05 15.61 5% 169,982 120,763 17.64 12.54 8% 151,507 107,837 15.73 11.19 10% 141,199 100,617 14.66 10.44 12.5% 130,075 92,819 13.50 9.63 15% 120,525 86,119 12.51 8.94 20% 104,990 75,207 10.90 7.81 View Large Assessing risk and probability Unlike reserves, which are volumes that are part of a development plan and are deemed to be commercially producible, Contingent Resources and Prospective Resources are not part of any development plan37 and there is a risk that the resources will not be produced. As previously noted, Prospective Resources represent the estimate of potentially recoverable volumes in undrilled exploration prospects; that is, they have not yet been discovered (and may never be). It is necessary to assess both the likelihood of discovery, referred to as the ‘Geological Chance of Success’38 (GCoS) as well as the likelihood of development if a discovery is made, or the ‘Chance of Development39’ (CoD). The product of these two probabilities results in the ‘Chance of Commerciality’ (Pc). Unlike Prospective Resources, Contingent Resources have been discovered but still may not reach commercial status (ie reserves) due to any number of contingencies. For instance, the volumes found may be too small, or too costly, to develop commercially. For Contingent Resources, it is necessary only to assess the Chance of Development. It is not possible to objectively measure the GCoS or CoD; rather, these are assessments based on inferences drawn from available data. There is well-established industry practice in estimating GCoS and the outcome is, for the most part, binary—there will be a discovery or there will not be a discovery.40 Estimating the CoD is more complicated as it requires the incorporation of a multitude of possible future scenarios that might include contingencies and indefinite delays. While size and economic threshold (the minimum economic field size) play an important part in the assessment, in areas (particularly environmentally or politically sensitive areas) where regulatory approvals are required, or where market conditions do not allow immediate development, this may not be the governing factor. As a result, the CoD may involve a significant amount of subjective assessment. Perhaps less intuitively, given that it involves something that is generally much less certain, the process for assessing GCoS is much better structured and accepted in the industry, which is generally guided by matrices of probabilities based on the confidence level (related to the quantity and quality of the data available) and the conclusions interpreted from such data. The assessment takes account of four critical parameters, set out below. For each parameter, the evaluator assigns a probability factor based on a review of all available information and the application of geological judgement. An example of the considerations and resulting probability ranges is shown in the chart below. However, there is no precise answer to this assessment because it is dealing with uncertain outcomes for each factor, and it also relies heavily on the experience of the evaluator making the assessment. The four independent parameters included in the evaluation of GCoS are as follows: Trap and seal: The chance that there exists a subsurface ‘closure’ that will provide a means to retain and hold any hydrocarbons that migrate into the reservoir. This requires the existence of a seal (the permeability barrier that prevents hydrocarbons from escaping sideways or upwards) as well as a structure or feature than will provide the means to trap significant volumes of hydrocarbons. Reservoir presence and quality: The chance that there exists a rock formation with adequate porosity and permeability to enable the accumulation and subsequent production of hydrocarbons. Hydrocarbon source: presence/quality, maturity and migration: The chance that, within the vicinity of a prospect, there are source rocks that contain organic matter in sufficient quantities and have reached sufficient ‘maturity’ (ie been exposed to sufficient pressure and temperature for enough time) such that hydrocarbons have been generated. In addition, hydrocarbon expulsion (ie the movement of hydrocarbons from source) must have occurred and there must have been pathways for the hydrocarbons to have moved out of the source and into the reservoir. Geological timing: The chance that the elements described above occurred at such times and in such a sequence that allowed for hydrocarbons to be generated and a migration pathway to exist to permit movement of hydrocarbons into a reservoir and be trapped there. In addition, the geological and hydrocarbon conditions must remain favourable for the accumulation to be preserved since entrapment (it is possible to trap hydrocarbons and then subsequent earth movements cause these to spill). Incorporating risk and probability The prior descriptions of classifying and categorizing reserves and resources, building a cash flow, and assessing risk may make it sound like this is a straightforward and somewhat linear process. In reality it is far from that and while there are many factors that may impact the cash flow (also discussed further in Part II), the application of GCoS and CoD in the case of Prospective Resources and Contingent Resources are two significant adjustments. The process by which these adjustments are incorporated is by reducing the cash flows (or the NPVs resulting from the cash flows) that it is estimated would result in the event of a successful outcome by a factor representing the probability of that outcome, and deducting from that the costs that would be incurred in the event of failure. This process may in fact involve more than one possible outcome, each being assigned a probability that, when combined, represent 100 per cent of the potential outcomes. The net result of these adjustments is to create a risk-adjusted NPV known as the ‘Expected Monetary Value’, or EMV. In its simplest form the probability of failure is taken as 100 per cent minus the probability of success. View largeDownload slide View largeDownload slide If the outcome from the cash flow above is assumed to represent the mean outcome if successful, but there is an assessment (GCoS multiplied by CoD, both conditions having to be achieved for success to occur) that there is only a 10 per cent chance of achieving success, then the expected NPV is only 10 per cent of that of the success case. In the other 90 per cent of outcomes (in this example), the Contract rightsholder is assumed to lose all of the capital. The full formula for calculating an EMV, if dealing with GCoS and CoD separately, is: EMV=GCoS*[NPVsuccess*CoD – E&Acost*(1−CoD)] – (1−GCoS)*Ecost, where Ecost is usually the initial cost of seismic and an exploration well being drilled, and E&Acost is the initial exploration costs plus the additional post-discovery costs (appraisal) that may be incurred before a project is deemed a success or failure (together the ‘risk capital’). Although not necessarily entirely correct, in many EMV assessments no additional Acost is assumed. If this is the case, then the equation can be more simply written as: EMV=GCoS*CoD*NPVsuccess – (1 – CoD*GCoS)*Ecost. Using these example probabilities, a set of EMVs can be calculated at different discount rates. Where the chance of success is thought to be low, and the risk capital sufficiently high, the EMV will be negative. Interpreting negative EMVs into market value can be complex, as there are other considerations. For example, if the risk capital represents a contractual obligation, then the EMV assessment would suggest that the asset represents a financial liability. If part of a broader portfolio the amount of the EMV41 may be deducted from the overall value. On the other hand, if there was no obligation to risk the capital, then logically that capital would not be spent, and so the asset may be deemed to have zero value. View largeDownload slide View largeDownload slide EMV ($M) At 1 January 2018 Pre-Tax Post-Tax 0% 12,246 6042 5% 7998 3076 8% 6151 1784 10% 5120 1062 13% 4007 282 15% 3052 (388) 20% 1499 (1479) Risk Capital ($M) 10,000 Chance of Success 10% EMV ($M) At 1 January 2018 Pre-Tax Post-Tax 0% 12,246 6042 5% 7998 3076 8% 6151 1784 10% 5120 1062 13% 4007 282 15% 3052 (388) 20% 1499 (1479) Risk Capital ($M) 10,000 Chance of Success 10% View Large EMV ($M) At 1 January 2018 Pre-Tax Post-Tax 0% 12,246 6042 5% 7998 3076 8% 6151 1784 10% 5120 1062 13% 4007 282 15% 3052 (388) 20% 1499 (1479) Risk Capital ($M) 10,000 Chance of Success 10% EMV ($M) At 1 January 2018 Pre-Tax Post-Tax 0% 12,246 6042 5% 7998 3076 8% 6151 1784 10% 5120 1062 13% 4007 282 15% 3052 (388) 20% 1499 (1479) Risk Capital ($M) 10,000 Chance of Success 10% View Large The assessment of risk and variability of reward are never straightforward and in practice the simple table below would actually be represented by a much wider range of outcomes. For example, the risk capital may be tax-deductible regardless of outcome, and be less on an after-tax basis. Further, given the uncertainty surrounding estimating probabilities, if the success case outcome were further assessed to lie between 1 in 10 (per the example above) and 1 in 5, then the EMVs would look very different. EMVs also do not need limiting to binary outcomes of success and failure. Multiple outcomes for full success, partial success/partial failure and full failure can be assessed and probabilities assigned to each outcome. The NPV of each outcome is then probability-weighted, and the result summed to produce the EMV. If modelled to account for many different scenarios and assumptions, this becomes a financial Monte Carlo analysis. EMV ($M) At 1 January 2018 Pre-Tax Post-Tax 0% 36,892 24,484 5% 28,396 18,553 8% 24,701 15,967 10% 22,640 14,523 13% 20,415 12,964 15% 18,505 11,624 20% 15,398 9441 Risk Capital ($M) 7000 Chance of Success 20% EMV ($M) At 1 January 2018 Pre-Tax Post-Tax 0% 36,892 24,484 5% 28,396 18,553 8% 24,701 15,967 10% 22,640 14,523 13% 20,415 12,964 15% 18,505 11,624 20% 15,398 9441 Risk Capital ($M) 7000 Chance of Success 20% View Large EMV ($M) At 1 January 2018 Pre-Tax Post-Tax 0% 36,892 24,484 5% 28,396 18,553 8% 24,701 15,967 10% 22,640 14,523 13% 20,415 12,964 15% 18,505 11,624 20% 15,398 9441 Risk Capital ($M) 7000 Chance of Success 20% EMV ($M) At 1 January 2018 Pre-Tax Post-Tax 0% 36,892 24,484 5% 28,396 18,553 8% 24,701 15,967 10% 22,640 14,523 13% 20,415 12,964 15% 18,505 11,624 20% 15,398 9441 Risk Capital ($M) 7000 Chance of Success 20% View Large As a result, there is always a lot of judgement in assessing value from EMVs. Technically, the NPV from reserves is also an EMV, although the term EMV is not usually used in this context. Once fully assessed, the NPVs for reserves and EMVs for different resources are additive in arriving at a value opinion for a portfolio. SUMMARY The valuation of oil and gas assets is about finding a number that reflects a balance of risk and reward. The process of valuation discussed in Part I of this article consists first of assessing the volumes of oil and gas that have been, or might be, discovered and remain to be produced, challenged by the fact that these cannot be measured directly. Instead, they are inferred through a rigorous and well-established process of data analysis of geophysical, geological, reservoir and surface engineering data. Having established the volumetric component of the analysis, the asset is examined through an economic model that projects expected future net revenue if the volumes in question are eventually produced, adjusting these where required for the assessed probabilities of those outcomes being achieved. Part II of this article will look in more detail at the economic analysis and some of the factors that influence the choice of variables in that analysis, and adds other means of validating results in order to settle on a reasoned opinion of ‘Fair Market Value’. Part II-INTRODUCTION Part I of this article focused on the general practice in the upstream petroleum industry to construct an analysis of the NPV or EMV of the forecasts of the likely future net cash flows from a property or portfolio of properties, discounted to the valuation date at a rate reflective of the nature and risk of the activities generating such cash flows. This element underpins the majority of valuations but is not, in and of itself, the ‘value’. Part II of this article focuses in more detail on utilizing the cash flow analysis to create a valuation opinion, and validating that opinion using other market metrics (which can also be used where the data required for a cash flow analysis are not available). It also comments upon a number of issues and considerations that come into play and may underlie the differences or be the cause of contention between parties who assert very different opinions of value. Various stages and considerations in building the cash flows and determining a value opinion from the results are discussed in the sections that follow: Understanding what is meant by ‘value’. What do we mean by Upstream Oil and Gas Assets? Valuation approaches. Reserves and Resources. Parameter selection and issues. Benchmarking. When taken together, what all the analysis is undertaking is to understand the balance of risks and rewards, and settle on a fair value that reflects that balance. View largeDownload slide View largeDownload slide Understanding what is meant by ‘value’ There is no formula or fixed rule for the assessment of value in the petroleum industry. In practice, market ‘value’ is simply an intersection of the views of a buyer and a seller. Where this intersection has been achieved in the open market without special factors impacting the considerations of one or another party, this is known as the Fair Market Value, or FMV. There is no universal definition of FMV, although all of the variants point to the same considerations as the definition utilized by the US Internal Revenue Treasury Regulation: Fair market value is the price at which the property would change hands between a willing buyer and a willing seller, neither being under any compulsion to buy or to sell and both having reasonable knowledge of relevant facts.42 On occasion, and under the guidelines of some industry bodies, the terms Fair Value or Market Value may be employed. It is not clear that there is any meaningful difference between the terms Fair Market Value, Fair Value or Market Value, and for the purposes of this paper the definition of FMV is used to represent ‘value’. While on occasion arriving at a single-point valuation number is required (for example, for a damages claim in arbitration or litigation proceedings), the generally accepted view among most valuation practitioners of petroleum properties is that, for any given property on any given date, there is a range of valuations within which a buyer and a seller could find a mutually acceptable intersection point to effect a transaction. This is well illustrated when observing cash bids in auctions of oil and gas properties; even eliminating ‘outlier’ bids there can be a substantial range of opinions as to an asset’s worth. Valuation approaches In Part I of this article, it was explained that it is the rights conveyed by a Petroleum Contract that have value, as these rights unlock the underlying profits obtainable from the oil and gas assets themselves. An oil and gas valuation exercise is about estimation of parameters than can only be measured or assessed indirectly (as also discussed in Part I of this article); about risks that similarly must be estimated using only experience and judgement; and about future economic conditions that can only be speculated upon. While all that might sound rather too vague for a valuation exercise, there are accepted techniques to address each of the uncertainties, even though any opinion should always be caveated as just that, an opinion, and in reality one that is subject to a range of uncertainty. There are three approaches that may be used in the valuation of upstream assets: Income Approach. This is usually the preferred approach, and requires the estimation of a future net cash flow from the asset. That estimation tries to model all the future potential and risks, and is the approach that is most specific to the asset itself. Despite the name ‘income’, this is very much about cash flow, and not about the accounting term ‘profit’. Market Approach. This approach seeks to benchmark what is understood about the asset against known sales of similar assets, or use metrics derived from corporate sales or the value of companies on the market. The limitation in this approach is that, unlike the stock market or real estate, the number of comparable transactions is usually very limited and, frequently, those may not actually be that comparable. Most valuers of oil and gas assets will use a combination of Income and Market Approaches, basing value heavily on the Income Approach and, unless there is a very specific marker transaction that points to value, using the Market Approach as a ‘reasonableness’ cross check. While both of these factors are commonly considered in deriving views as to value, the weighting between them (or the reliance on one over another) is a function of many variables and considerations. Cost Approach. This approach is rarely used in the valuation of Petroleum Contracts, and is reserved more for the valuation of tangible assets. It seeks to value the asset based on its actual cost, or its depreciated replacement cost. On occasion, for example in the very early life of a Contract that has only exploration potential, parties may agree on value reflecting the past investments of the seller. As noted in Part I of this article for the most part tangible assets supporting production under a Petroleum Contract are not valued separately nor added to the value estimate derived from the Income and Market Approaches. If they were valued and sold there would be no equipment to produce and sell the hydrocarbons unless they were replaced, in which case their revenue would have to be offset by the cost incurred to replace them. Thus, tax benefits aside, the Income Approach ignores sunk (past) cost and looks only to the future. Residual salvage value, to the extent it exists, will also be reflected as income at the relevant point in the future, just as the cost of abandonment and site restoration represent a future liability. Overall, the valuation process consists of the exercise of creating all the inputs to the cash flow(s) to be evaluated, including building the model that represents the terms of the Petroleum Contract and applicable fiscal terms from the jurisdiction in question; from searching and assessing the comparability of relevant market transactions and information; considering the various risks and probabilities of each outcome being realized and ensuring these are appropriately embedded in the analysis; and from reviewing the range of these outputs resulting to derive an opinion of the likely value in the market. Reserves and resources In Part I of this article, it was explained that it is the rights to produce and sell hydrocarbons (the Petroleum Contract) that hold the key to value, it is what those rights constitute in the subsurface, and the means of development and production that is important to understanding how that value will be unlocked. As also detailed in Part I, this requires estimating the volumes of hydrocarbons in the ground and the proportion of these that might be recoverable, the costs of doing so, what they might be sold for and the risks attendant in the various steps along the way. Typically, valuations will focus on the main risk classifications used to describe the hydrocarbons in the subsurface. Although some countries, jurisdictions and organizations use different or slightly different terms, those main classifications are known as Reserves, Contingent Resources and Prospective Resources.43 Stepping away from defined terminology, these may often be referred to as Reserves, Discoveries, and Exploration Upside (or Exploration Potential). Reserves are the best known classification of hydrocarbons and, in most circumstances, have the highest unit value. They are also the only classification that is routinely reported to regulators and stock exchanges and, as a result of their status, contain the least amount of uncertainty about their future producibility. Contingent Resources are clearly a risker class of asset than Reserves. There is fundamental uncertainty about whether they will ever be developed (hence the ‘contingency’) and because they have yet to be developed there will usually be a larger range of uncertainty around the range of volumes that may be produced. However, it is also possible that Contingent Resources expected shortly to be approved for development, and Reserves that have only just been approved but have yet to be developed, may in fact share very similar uncertainties with regard to the volumes to be produced and be differentiated only by approval risk with regard to the Contingent Resources project. While, on a unit basis, Contingent Resources will typically be worth less than Reserves, to the extent that Reserves are small and the Contingent Resources are large, the total value distribution in a portfolio of multiple assets could be the other way round. As with Contingent Resources, the fact that Prospective Resources carry significant risk, and are not Reserves, does not make them without value. Where there is perceived to be a sufficiently large upside, and a belief that the risks are not excessive, then the exploration potential may still place a value on a Contract of hundreds of millions of dollars (as most recently seen in auctions for exploration properties offshore Mexico and Brazil). Parameter selection and issues Part I of this article described the process of estimating hydrocarbon volumes, classifying them and building a model to represent the future net cash flow to be expected. Part II provides a deeper discussion regarding understanding issues around the choice of some of the parameters that are used in the cash flows in the Income Approach, and other considerations generally that may assist in understanding where some of the ongoing uncertainties lie. Probabilities Oil and gas exploration and production is an inherently uncertain business. Probabilities are used extensively in geoscience and petroleum engineering, and are similarly applied in the assessment of value. The most common usages are in the categorization of reserves, and in the estimation of the probability of success or failure of an exploration well or of a project proceeding (GCoS and CoD, respectively). However, they can be, and are, used at all stages of an evaluation to allow the assessment of risk and reward, on the basic principle that for there to be value the potential gains, adjusted for risk, should exceed the cost of pursuing those gains. While the application of probabilities is standard, a key point to reiterate and appreciate is that they are estimated, not measured. While empirical evidence would suggest that the estimation techniques and range of probabilities utilized in oil and gas evaluations are generally reasonable at a portfolio level, individual estimates may be subject to significant variation and differences of opinion. 1P, 2 P or Mean? Part I of this article described the process for determining reserves categories, Proved, Probable and Possible (and similarly, combined as 1P 2P and 3P). What was not discussed was which of these should be used for valuation purposes. Corporate finance theory dictates that value should be based on the ‘expected’ future net cash flow, which generally speaking is the same as saying the weighted average or mean cash flow. However, typical approaches to valuation in the marketplace do vary across the world. Historically the USA has based valuations on Proved (1P) reserves. The origins of this standard are owed to history, as under modern definitions the expectation is that Proved reserves will be exceeded on most occasions. Indeed, until very recently the Securities and Exchange Commission (SEC) regulations in the USA prohibited public companies from reporting other than Proved reserves and, while this limitation no longer exists, 1P remains the standard. In much of the rest of the world, the typical approach has been to use Proved plus Probable (2P) reserves as the valuation standard. While not identical to the mean (except in the case of a normal distribution of outcomes), the 1P reserves usually reflect an outcome very close to this, and has the advantage of being a standard reporting metric (which although easily calculated, mean reserves are not). This presents a potential dilemma as it would suggest that the same asset, all else being equal, would have different values simply because of location and historical norms. In practice, the issue may be more theoretical than real. If the only data available on which to base a cash flow are the 1P reserves, the issue is moot and value will be based on 1P. However, if all the base data is available allowing the assessment of 1P and 2P reserves, the latter should be applied, even if benchmarking is carried out using the 1P reserves against 1P comparable transaction metrics (if these are the only ones available). Where Proved, Probable and Possible reserves are available (whether as stand-alone categories, or as combined in the 1P, 2P and 3P categories), and cash flows can be run on each, there is an approach known as Swanson’s Mean which combines these into a mean value. This takes 30 per cent of the 1P NPV, 40 per cent of the 2P NPV and 30 per cent of the 3P NPV, and adds them. The reason for running cash flows at each reserves category, rather than combining the inputs of the underlying cash flows and then running a single expected (mean) cash flow, is that results are typically not linear. On the one hand there may be economies of scale as projects get bigger, providing a higher unit value at the upper end. On the other hand, many jurisdictions have ‘progressive’ forms of tax or production sharing whereby larger or more profitable projects provide for higher government take, reducing the unit value to the Contract rightsholder at the upper end. Thus, while running cash flows at difference reserves or resources confidence levels and combining the results into a mean is the best way to evaluate value, it suffers from having to run three cash flows rather than one. Further, although in theory this should not be the case or an issue, the upside case (3P reserves, or High case in resources) can tend to suffer from an ‘everything going well’ syndrome, and reflect a combination of outcomes that may in reality be somewhat less likely than the implied ‘10% chance of being exceeded’. Thus, there can be some reluctance to burnish value too much with weight from the upside. As a result, on occasions where time is of the essence or where data limit the ability to run three cash flows, or where the upside (3P / High case) may look particularly large, only the 1P or 2P (or Low/Best cases for resources) cash flows are used as the basis of valuation. Although seemingly a violation of best (ideal) practice, when combined with input from the Market Approach, and potentially in the context of a large portfolio, this does not necessarily bias a valuation opinion. However, it is important to understand what production stream has been used, and why. Valuing portfolios and multiple assets One of the challenges when faced with a portfolio of assets is ensuring that inter-dependencies are adequately addressed. Each asset is typically considered independently in the first instance. In the case of reserves, this is usually less of an issue as reserves definitions require that these volumes are tied to explicit project (investment) activities; for there to be reasonable certainty of the investment taking place there also needs to be reasonable certainty as to the timing of activity. However, both Contingent Resources and Prospective Resources not only have meaningful contingencies of their own, they may also have additional contingencies depending on the performance of other assets in the portfolio. An example may be found in considering the EMVs of an exploration portfolio. An EMV can easily be calculated for each exploration prospect on its own. However, if a company has many prospects then not all will be drilled concurrently. Thus, it is necessary to consider a timeline for the drilling, and how any capital constraints may cause this timeline to play out such that exploration spend is limited to an appropriate proportion of a company’s overall spending. Further, in the case of exploration in particular, there are frequently dependencies between prospects. This may reflect prospects of a similar type, where success or failure of a first or early well may improve or downgrade the likelihood of success of other prospects in the portfolio. These dependencies must be further estimated and taken into account. There are also management considerations whereby one or more early failures may cause abandonment or indefinite deferral of an entire drilling campaign, with commensurate impact on overall value even though the remaining undrilled prospects had positive EMVs at a point in time before the first well was drilled. The FMV is rarely a simple addition of stand-alone EMVs of all prospects in a portfolio. A similar consideration can also apply in Contingent Resources, with unconventional resources providing a good example that was reflected in the recent oil price downturn. Technical assessments may have led (probably inappropriately) to a very large area covering hundreds or even thousands of drilling locations to be classified as ‘reserves’. The cost of drilling these would have represented a very significant future capital outlay, but one that would have been spread out over many years. If properly classified, a company would have been required to give proper assurances that it planned to drill all of these over the coming years, based on the logic that if the hydrocarbons could adequately be identified, over time they would naturally drill and develop every viable location. This is analogous logic to the expectation for development of a conventional discovery, although with the major difference that the conventional discovery will typically have far fewer wells and be developed over a much shorter time frame. There are good arguments that, notwithstanding the classification of these large volumes as reserves, not all of them should have been and some should have been classified as Contingent Resources simply because there could not be reasonable certainty that all the identified locations would be drilled in the manner implied by classifying them as reserves. However, in many cases companies assigned reserves for unconventional portfolios lasting many, many years. When the oil price dropped, two linked phenomena came to the fore. First, some locations were no longer economic at the new price, cutting a large number from the reserves category. Of course, this factor impacted all projects and was not in and of itself a reason to disqualify them originally as having been classified as reserves. However, second, as a result, the reduced income from lower prices further reduced cash resources to fund the drilling programme of the company, taking even more volumes out of the reserves category. The higher the financial leverage of the company, the more this impact was felt. While all projects are exposed to the risk of a major unexpected change in oil and gas prices, assets where development activities are scheduled (and assumed) to take place over many years are particularly vulnerable to changes in activity plans. This can be compared to the number of very expensive deep water projects where most of the capital is spent prior to production commencing. While projects at a very early stage may have been deferred (and potentially been dropped out of the reserves classification as a result), those where a significant portion of the capital had already been spent or committed (and therefore had much less capital to deploy in the future) remained subject to development. This risk of delay, deferral or discontinuation of project development is therefore often much less for a project where capital is spent up front (providing that capital has already commenced being expended), than for projects where significant capital expenditure takes place over the long term. Whether addressed through a more considered allocation of volumes between Reserves and Contingent Resources (and potentially even Prospective Resources, where technically appropriate), or even if they have been classified as reserves by applying greater risk factors to activities the further out in time that they are assumed to happen, these risks do need incorporating. Discount rate The discount rate to apply can be very contentious as, depending upon the profile of the cash flow, it can make a substantial difference to the value derived. It is not the intention in this article to go into the full derivation of the discount rate. However, the key point around which argument tends to revolve is the adjustment for risk. The discount rate that should be applied to a cash flow stream is that which properly reflects the systematic risks of that cash flow, but not its specific risks. Put into more straightforward language, the discount rate should incorporate a factor for risk that cannot be diversified away in a portfolio and to which everyone investing in this particular type of cash flow is subjected. Risk that is specific to a cash flow should be accounted for by adjusting the cash flow itself, such that the cash flow ultimately being discounted is the ‘expected’ or risk weighted cash flow. While the theory is straightforward, this is not universally reflected in practice. The main reason for this is a combination of the number of risks that need (or would need) incorporating into a cash flow, and the difficulty in deriving the appropriate risk adjustment for each. It is far easier (even if not theoretically pure) to make a single adjustment to the discount rate, than attempting multiple specific adjustments each of which may be subjective and time consuming. The two aspects that are most touched by this consideration relate to political, or country, risk and to the risk category of cash flow (for example, the cash flow from a simple producing reservoir with no further required investment, or a complex undeveloped asset). There is a substantial body of opinion that argues for adjusting for country risk by adding to the discount rate the premium that exists in a country’s equity risk premium (versus that of the USA), or the premium implied by Credit Default Swaps. While these factors are readily available on the internet,44 used without further adjustment they potentially overstate the risk for investments in oil and gas where the commodity price and many costs are U.S. Dollar denominated, and while the cash flows are subject to regulatory and political risks, they are not subject to the same currency and inflation risks that other in-country investments may be (and that are reflected in that risk premium). The adjustments for the risk category of the cash flow are less clearly defined and indeed, often no adjustment at all is made and a single discount rate is used for all categories of cash flow. It is common practice to use a discount rate that represents the Weighted Average Cost of Capital (WACC) of a company or selection of companies (adjusted to remove the effect of financial leverage) as representing the average discount rate applicable for upstream oil and gas cash flows. However, as the name implies, this is an ‘average’, and is not necessarily representative of the discount rate appropriate for a specific project or project type. While there are published sources45 that survey for such adjustments, the absolute results of the survey are not considered reliable indicators that can simply be applied ‘as is’.46 However, it is evident that such categorization of cash flow streams and different discount rates is appropriate, just in the same way that the cash flows from utilities are less risky and are discounted at lower rates than the cash flows from startup IT companies. Specifically, the future cash flow of a mature producing asset not requiring further investment can be forecast with more precision and much less variability (volatility) than the prospective future cash flow from an exploration drilling project. Even after the latter has been adjusted for its specific risks (GCoS and CoD), it is inherently much riskier (subject to much greater variability around its mean) than that of the mature field and thus, according to corporate finance theory, should attract a higher discount rate. Such adjustments do occur, but not in a systematic manner across the industry or valuation practitioners and they give rise to significant arguments when it comes to discount rate. Notwithstanding, discount rate is just one of the parameters used to value an asset, and it may be that the impact of differences on other parameters is to reduce the bottom line difference, particularly when everyone is taking into account the value implications of observing market transactions on similar assets. The same issues apply with regard to operating leverage. While the financial leverage of firms is removed from the valuation of assets, operational leverage will normally transfer with the asset. A classic example of this relates to equipment leasing, using as an example an offshore field. The same field could be developed using fixed assets including platforms and pipelines that are constructed and paid for prior to production, with a relatively low operating cost thereafter. An alternative might be to undertake the development by leasing a Floating Production, Storage and Offloading (FPSO) unit. In this case, there is a much lower up-front capital requirement, but much higher operating expenses as the FPSO costs are spread out over the life of the field. In the former case, in the event a field under-performs (or oil prices drop), then a field may still continue to operate in a cash positive manner as the operating expenses are much lower than even the reduced revenue. In the leased FPSO case, the revenue being received may fairly quickly fall below the operating costs, including leasing costs. Unless renegotiations can provide a solution, logically the field would then be shut in although the lease still represents an ongoing obligation. There are examples of this arising from the 2014 oil price crash, with years of renegotiation and/or litigation to follow. This aspect of discount rate is likely to remain an issue for some time unless and until more reliable research and analysis is undertaken. Oil and gas prices There is no hard rule for determining the future oil and gas prices that should be applied to a cash flow analysis. While they need to conform to ‘market’ in the sense that the resulting valuation is intended to be a valuation reflecting market conditions as of the valuation date, there is no database of future prices that can be accessed and the ‘correct’ future price deck extracted.47 Selection is a judgement on what the future may bring, aided by examination of sentiment as published in the press and in analyst reports. While oil and gas companies may provide indicators of where they believe future trends will or should lie, they rarely speculate in detail both for competitive reasons and to avoid any anti-trust claims. A further indicator is the price of oil and gas futures (as traded on the commodity exchanges). There is significant debate around the extent to which these are a true predictor of future prices. Empirical data suggest that near term (perhaps 1–2 years out) they fairly readily reflect market sentiment. However, trading in futures contracts becomes much thinner (lower volumes) moving out in time, and while the longer-term futures price may provide some guidance it is not considered reliable as a hard indicator. A frequent approach taken for valuation is to use futures prices for a period of 1–3 years, and then assess a market-related outlook thereafter. There is also a further misconception with regard to the oil and gas prices used in connection with reserves, although different in different jurisdictions. The SEC mandates the oil and gas prices to be used in reserves assessments as the average realized in the prior 12 months, held flat going forward. However, that only impacts companies reporting under SEC jurisdiction. Companies reporting under Canadian NI 51-101 regulations have latitude (within reason) to set their own oil and gas price projections, including future price escalation assumptions, although these must be published. Companies reporting under regulations of a number of other regulators around the world have similar latitude, although regulations are not as precise. These differences may give rise to differences in volumetric estimation (to the extent this occurs it is most likely to impact the economic limit at the tail end of a well’s or field’s life), but even if there is no volumetric difference, the estimated future cash flows may be meaningfully different. In the case of companies reporting under SEC regulations, it is clear from where the price derives and there is no necessary correlation between that price (backward-looking) and market sentiment for the future. However, that argument does not necessarily apply in respect of Canadian and other reporting jurisdictions where the companies select the price assumptions. The theory behind allowing this choice is that reserves should reflect future expectations of field management and investment/development, itself substantially influenced by oil and gas prices. Thus, the future oil and gas prices used for reserves should reflect a company’s future planning assumptions. That said, planning assumptions have been known to build in degrees of conservatism,48 and it is not necessarily true that oil and gas prices used in a particular company’s planning assumptions would reflect what either the company, or market in general, would credit in valuing a future opportunity. At the end of the day, the choice of future oil and gas prices to be used in a valuation is in the hands of the valuer. It requires justification, and that justification will reflect a significant number of inputs. However, like many other valuation parameters, this remains something over which parties may reasonably disagree, without any one being able to claim that their opinion is the only correct one. Inflation and exchange rate While inflation and exchange rate are two separate issues, there is a necessary connection. When dealing with the value of assets in any country other than the USA, the chances are that some elements will be impacted by currency. While oil is mostly sold in US Dollars, gas may be sold in local currency (not linked to the exchange rate) and locally incurred costs, particularly labour costs, are usually in local currency. This therefore gives rise both to currency exposure, and to local inflation, which may be significantly different from US inflation (taken as the benchmark). Inflation is a separate issue in its own right, discussed further below under Real and Nominal Cash Flows. Theory would suggest that the exchange rate between the currencies of two countries that have different inflation rates should move to compensate. This is logical because otherwise the same piece of capital equipment sold in each of the two countries would end up having different prices in each, simply because of the changing exchange rate. Indeed, this is what does in fact happen for a certain period of time. However, in the absence of regulatory barriers that cause just such dislocations, this cannot continue forever or market arbitrage will occur, people will buy that good from the cheaper country and resell, without risk, in the more expensive country. This is also why forward currency rates in open markets also reflect interest rate differentials. Valuation practice therefore assumes that where there is an inflation differential impacting costs and revenues, the exchange rate is also adjusted proportionately49 such that there is neither financial gain nor financial loss as a result of this phenomenon. Real and nominal cash flows Cash flows may be run as either Real or Nominal. However, the terms themselves are often poorly understood and while the results from either approach should be identical, small errors can readily creep in. ‘Real’ cash flows (also known as Constant currency cash flow) are where the cash flow is stated in terms of the value of the currency at a specified date.50 No inflation is applied to costs or revenues, as both reflect the base year (real) currency units, although this should not be confused with changes expected from non-inflationary factors. The main issue that needs addressing is in respect of depreciation (for tax purposes) where this takes placed over a number of years. In reality, one dollar of depreciation in Year 2 is worth less than that same dollar of depreciation in Year 1. Thus, depreciation needs adjusting down by the forecast inflation rate for each year from the year of investment until the point where that depreciation stream is fully utilized. The discount rate that is applied to the cash flows should also be a Real discount rate or otherwise different NPVs will result from Real and Nominal cash flow approaches. ‘Nominal’ cash flows (also known as Current currency cash flows, or Money-of-the-Day cash flows) include escalation and inflation factors for oil and gas prices, and costs. No adjustments are necessary for depreciation. Most cash flows run are Nominal, largely because it is easier to do so. However, there is a further aspect that can be confusing. It is not unusual for valuers also to run ‘flat’ (unescalated) cash flows. Flat cash flows do not include any inflation on prices or costs, but they are in fact a Nominal cash flow; they simply use an assumed future inflation rate of zero. The cash flows that support SEC reserves statements are flat cash flows. The reason for considering flat cash flows (other than because the SEC mandates these in its reporting) is to evaluate the impact on NPV of the inflation forecast in the Nominal cash flow. Although it is reasonable to assume that, over time, inflation will have an impact, a look back over the past 30–40 years shows that this impact is anything but straightforward. While there have been periods where oil and gas prices rose spectacularly, and costs followed a little while thereafter (for example, 1974–79, and 2000–08), there have also been periods of price crashes, cost reductions and many years of largely flat prices (for example, the period 1986–2000; the jury is still out on the how the longer-term will evolve from the 2014–16 price crash), notwithstanding the very recent price increases. While similar volatile trends to the past could be forecast into the future, it is hard to incorporate these into a FMV that also assumes both buyer and seller share the same or a comparable view. Thus, Nominal cash flows tend to have relatively modest but steady inflation assumptions incorporated, potentially capped to limit the impact over a long period, and sanity-checked by comparing to the results from a flat cash flow (‘what would be the outcome if nothing changed?’). Tax Tax usually refers to Income Tax. Special taxes applicable to a Petroleum Contract (or upstream oil and gas activities in general) are always deducted. However, Income Tax may have more complex considerations, particularly in those countries where profits and losses can be grouped. Nonetheless, the implications of income tax do need addressing and embedding in the cash flow just like any other (potential) deduction. In many jurisdictions, there are tight ring-fencing rules that limit the ability to avoid income tax at a project/field level, and the calculation may be straightforward. However, where companies can defray the impact of tax by bringing in past loss carry-forwards, or current losses or depreciation from elsewhere, the tax calculation may be considerably more complex and challenging in terms of determining its impact on FMV.51 In the USA, it is also common for the cash flows supporting reserves reports to be presented pre-income tax. This is in part because there is no simple connection between the taxable profit contribution of a well or field and the overall tax liability that a company may face. In certain jurisdictions, a company with large tax losses (or in market conditions where these may widely exist) may be able to shelter a substantial portion of profit from a field and increase its value over what a fully-taxed consideration would be. The only clear point on this is that income tax should always be considered. However, the nature and extent of its impact may be quite variable, adding yet another source of difference to value considerations. Benchmarking While the Income Approach tends to be the method most favoured in valuations, it has one potential problem; it can only properly be used when there is sufficient data to create a cash flow projection. While there usually is that data in a structured transaction, this might not be the case in some circumstances such as screening exercises, where there may be a hostile takeover and no access to the target’s data, or in disputes where one party is unable to access the necessary data. In such cases, it may be necessary to lead by using metrics derived from public domain information (the Market Approach). However, in most cases the Market Approach is used to benchmark the results of the Income Approach. It can take two forms: Transactional Data: Using the metrics from transactions that have taken place, and where there is sufficient information reported in the public domain (either previously or in connection with the transaction) in order to derive those metrics. These will typically take the form of dollars per barrel or thousand cubic feet of (1P or 2P) reserves; dollars per barrel or thousand cubic feet of daily production; or dollars per acre of Contract area (in the case of undeveloped properties). View largeDownload slide View largeDownload slide Trading Data: Taking data from the market performance of listed oil and gas companies, and disaggregating these into similar unit metrics as for transactional data. The great advantage of the Market Approach is that it ties value to actual observed data, just like trades in stocks and shares, or transactions in the housing market. However, the main challenge facing it is that instead of millions or perhaps hundreds of transactions with which to benchmark value, except on relatively rare occasions the data available from which to determine the benchmarks tend to be sparse and not always close either in location or time. Nonetheless, trends can be observed, and the Market Approach is extremely useful either in anchoring or in setting limits to the conclusions that have been derived using the Income Approach. While the transaction and trading data approaches are useful for benchmarking, it also needs recognizing that market data also point to a very wide variation in valuation opinions. This can be seen in cash bonuses paid in public asset or lease auctions. There is a very long timeline of data in the US Gulf of Mexico for exploration leases, which are awarded based on cash bids. This shows that it is common for the winning bid being a multiple of 2× to 4× the mean bid (with the range between winning and low bid being many times higher). View largeDownload slide View largeDownload slide A similar pattern was seen in 1997 when Venezuela auctioned 20 contract areas, most containing some production in mature oil fields. Here the winning bid over all contract areas was twice the average, and the range on some blocks was 10× or more. The main difference with the Gulf of Mexico auctions was that bids on each block were revealed in real time, with bidders having the opportunity to amend their bid (if they wished) before the next block was offered. View largeDownload slide View largeDownload slide The point in both these examples is that what is published in public data is the metric of the winning bid. While that does indeed set a market price (a transaction was concluded at that price point), it also highlights that in many cases there is an extremely wide variety of opinions as to value. In a buoyant market, it may be reasonable to assume that there will exist one ‘outlier’ that will be prepared to pay the higher price. However, in a more difficult market, or in a market as recently seen in the price downturn with a wide spread between seller and buyer expectations, or generally where liquidity has been squeezed, over-reliance on past market data may result in generous outcomes. Summary In two parts, this article has described the process of building, and then benchmarking data leading to an opinion of fair market value of upstream oil and gas assets. While this article covers a lot of ground and raises a number of issues, the topics it addresses are very broad and it is impossible to cover everything. Further, some issues are very complex and are not always black and white. The purpose of this article has been to describe those components within a conceptual framework that would be clear to non-technically trained or experienced readers. Hopefully, despite omitting some topics and simplifying others, this has not caused any aspects to be misleading or give the impression that by following what is said here an opinion that defines ‘the’ value will always be achieved. Value is inevitably an opinion, hopefully rational and consistent with data available to guide it, but always subject to reasonable differences. Footnotes 1 This would involve valuing the distributions out of a company (dividends, debt and other instruments), plus take into account factors such as the future growth potential of the company. 2 Chemically CH4, also often referred to as C1. 3 Carbon dioxide (CO2) and hydrogen sulphide (H2S) are two common impurities. 4 In the very best reservoirs, typically very unconsolidated sands and gravels, this may rise above 30%. But such high porosity is relatively rare and only exists in limited sections. 5 Not to be confused with oil shale, which is a bituminous (kerogen) shale and from which oil is extracted by heating in situ or following extraction by mining. 6 There is a continuum between low-quality conventional reservoirs with limited porosity and permeability, and dense source rocks with virtually no porosity and permeability. Porosity is the space between the grains that make up the rock; permeability is the connectivity between those spaces that allows the movement of hydrocarbons. 7 Liquid Petroleum Gas, or LPG, is a component of NGLs. 8 While this may occur, it is not always so and any NGLs subsequently produced may be reported as a part of the overall gas volume. 9 Using the velocity of sound through the various layers of rock. 10 Cores are physical samples of the rock recovered from the subsurface during drilling or logging activities. 11 Well logs are obtained from devices that are lowered into the well on electric wireline (or, these days, may be incorporated in the drill string and measured while drilling) in order to measure and record certain rock properties, from which the parameters of interest may be calculated. 12 Also known by the acronyms STOIIP (Stock Tank Oil Initially In Place) and GIIP (Gas Initially In Place). 13 The proportion of oil and gas in place that can be expected to be ultimately produced. 14 The geological model is known as the ‘static’ model, and the production simulation as the ‘dynamic’ model. Together the process undertaken is known as reservoir simulation. 15 Corrected to adjust for the compressibility factor deviation from an ideal gas. 16 Also known as the Estimated Ultimate Recovery, or EUR. 17 As hydrocarbons are withdrawn from the reservoir and the pressure drops the weight of the overburden (overlaying layers of rock) can compress the rock, particularly where the reservoir is soft or not well consolidated. 18 The energy imparted to the reservoir by compaction may otherwise seem like the effect of additional gas, which is not in reality present. Compaction occurs after fluids are withdrawn from a reservoir and the weight of the overlying rock can overcome the natural strength of the reservoir rock. It occurs most frequently in soft and poorly cemented reservoirs. 19 Exponential, Harmonic and Hyperbolic Decline. 20 Technically, the term ‘reserves’ is a class of resources, which when used in the generic sense covers all classes of hydrocarbon volumes. However, as the two other classes also incorporate the word ‘resources’, it is just used in this article when referring to those classes, and not in the generic. 21 Definitions and a more comprehensive description of PRMS can be found at <https://www.spe.org/industry/reserves.php>. Additional information on the Canadian NI 51-101 can be found at <http://www.albertasecurities.com/industry/securities-law-and-policy/_layouts/Regulatory-Instruments/RegulatoryInstrumentDispForm.aspx?List=c425783b-0214-41e1-bc6a-66e6766ff3aa&ID=104&Web=729da164-5e70-47a7-bdea-6a26546e92e3>, and SEC definitions at <https://www.sec.gov/rules/final/2008/33-8995.pdf>. 22 Do not confuse estimates of ultimate recovery with reserves (except where a field or well has yet to commence production). Reserves are what are still left to produce. 23 The actual test is defined as a ‘reasonable expectation’ that the volumes will be developed. Unfortunately, there is no absolute measure of this level of certainty, but it is deemed to equate to a high degree of confidence. Where definitions refer to probabilities, this is assumed to be a 90% or better chance of being achieved, always noting that such probabilities cannot be measured and are simply a reflection of judgement. 24 The official language used is ‘sub-commercial’. However, this does not adequately describe all the situations that govern Contingent Resources. 25 Not to be confused with common industry jargon or ‘P1’ for Proved, ‘P2’ for Probable and ‘P3’ for Possible. 26 See discussion in Part II on probabilities. 27 These probabilities should not be confused by taking 90% of 1P, and 50% of Probable (2P-1P), etc. The percentages simply state the accepted chance that the particular reserves volume will be achieved (or not), not by how much it will be exceeded or fall short. 28 On a 360o basis there are actually eight equally-spaced locations that surround one well, each location being the area that will be drained by one well. The exact distance will be determined by the characteristics of the reservoir in question. 29 Although this standard is used by some companies, others may use a slightly lesser standard reflecting a ‘reasonable expectation’ that such approval will be forthcoming in the near future. 30 Also frequently referred to as the P90, P50 and P10 estimates; see discussion below on Probabilistic estimation techniques. 31 Mathematically simulating hundreds or thousands of random combinations of input parameters to produce a range of results. 32 For instance, in the absence of other reliable data, the assumed water contact level for Proved reserves is limited to the lowest known occurrence of the hydrocarbon (gas or oil) seen in a well. 33 Value as of a specific date should only take into account information that was known or knowable at the time, including the state of the market. 34 It is common practice in North America and elsewhere to show Revenue Interest (also known as Net Revenue Interest, or NRI) as being the working interest after deduction of royalties. In other locations, Revenue Interest may be shown as the same as Working Interest, even where a royalty is payable, with the royalty treated only as a fiscal (rather than production entitlement) deduction. 35 This example shows results annually; cash flows may also be run at other time intervals, typically monthly or quarterly, and results summed to annual for display purposes, or displayed in months or quarters. 36 A cash flow discounted at a 0% discount rate is the same as the undiscounted cash flow. 37 While there may not be a formal development plan for contingent and prospective resources, the estimates of recoverable oil and gas should be based on an understanding of a likely development scenario. 38 There are a number of abbreviations used for this in the industry. Geological Chance of Success appears as Chance of Geologic Discovery (Pg) in the PRMS. 39 ‘Pd’ in the PRMS. 40 In reality, there is the potential for ‘uncertain’ outcomes, although those are generally not incorporated in such analysis because of the complexities they introduce. 41 Limited so as not to exceed the cost (penalty) of not spending the amount specified in the contractual obligation. 42 Title 26 CFR 2009, Internal Revenue, §1.170-1. 43 See <https://www.spe.org/industry/reserves.php> for the PRMS definitions. 44 For example, <http://pages.stern.nyu.edu/∼adamodar/>. 45 <https://secure.spee.org/resources/annual-spee-survey>. 46 Discussion on this goes beyond this article. 47 Unless, for example, the product is sold under a long-term contract where prices are explicitly defined. 48 It always being better to surprise to the upside than disappoint on the downside. 49 Known as Purchasing Power Parity. 50 Usually this is as of the first year of a cash flow (but does not necessarily need to be so). 51 This is a complex consideration because if only the seller has the tax situation under consideration, the market as a whole may not pay for this, as a typical buyer would not be able to use it. © The Author(s) 2019. Published by Oxford University Press on behalf of the AIPN. All rights reserved. This article is published and distributed under the terms of the Oxford University Press, Standard Journals Publication Model (https://academic.oup.com/journals/pages/open_access/funder_policies/chorus/standard_publication_model)
TI - Valuation of upstream oil and gas assets
JF - Journal of World Energy Law and Business
DO - 10.1093/jwelb/jwz007
DA - 2019-04-01
UR - https://www.deepdyve.com/lp/oxford-university-press/valuation-of-upstream-oil-and-gas-assets-8LzAsK1cc0
SP - 121
VL - 12
IS - 2
DP - DeepDyve
ER -