Economic analysis is, in this context, the translation of barrels of recoverable oil or cubic feet of gas into dollar value. There is an interaction between the meaning of "recoverable" and economics, because secondary recovery is more costly than primary, not to speak of enhanced recovery. When we say "dollar value" we have to make clear whether we speak of real value (considering inflation) and/or present value (money in the future has normally less value than today). Oil and Gas prices obviously are most important amongst the various factors in the calculation. Unfortunately, such prices are quite unpredictable in the long term, such that calculations are often made for a number of oil price scenarios. To complicate matters further, the types of contract that govern the possible profits for a company are many, and history has shown painfully that a contract may not last till its specified end date, through a sudden re-negotiation or nationalization. These aspects will be highlighted in the following pages. You may also find the paper by Haldorsen (1996) useful as an introduction that covers most of the economic aspects of evaluation and decisionmaking. A more recent book that has been made available on the internet is by Kasriel & Wood (2013), which is specifically aimed at the Upstream.
Most of the time, things we buy get more expensive. The consumer price index keeps track of that development. Inflation is in Europe a few percent per year, in Zimbabwe it has been at times a few billion percent! Price index is used to translate ""Nominal dollars" into "Real dollars"
Real Value (or Real Terms)
The value of a dollar linked to a particular year. The oil price during the oil crisis of 1979/1980 was 32$. ("in 1980 dollars"). Now in 2010 this price is misleading, because after 30 years of inflation, it would be more meaningful to translate it in "2010 dollars", which amounts to 72 $. So a real dollar, or constant dollar is adjusted for inflation.
Now assume that the year is divided into m equal parts. The interest over the m-th part of the year is i/m. Hence:
Cash Surplus is the result of a cashflow calculation, taking it to the end of the life of the field. If in Present Value and net of tax we can call it the PVNCS, a nice yardstick to compare opportunities and to estimate the Expected Monetary Value (EMV).
Earning power is the pv discount rate that makes the pv cash surplus equal to zero. The higher the earning power (%) the better the opportunity. It is often calculated by an iterative procedure attached to the cashflow calculation.
The pay-out time is the point in the cashflow curve where it crosses the zero line. In other words, how long is the expenditure more than the revenue, and in present value terms. The shorter the pay-out time the better.
Capital Expenditure (CAPEX)
These include the costs of development installations, such as building roads to the site, drilling and completing wells, construction of pipelines, etc. This is also referred to as capital expenditure ("CAPEX"). It may be that a reservation has to be made for the cost of abandonement. For instance a production platform may have to be dismantled and removed. This is also included in the CAPEX.
Operating Expenditure (OPEX)
The cost of consumables and personnel and contractors delivering services during the whole of the production phase are covered under the operating costs, or operating expenditure ("OPEX"). The operating costs start in the year that production starts. The annual amounts are often estimated by a rough rule of thumb to be 5% of the total capital costs. The reason behind this is that the larger the field, the more wells, etc. the higher the capital costs and at the same time more work involved in maintaining and controlling production operations.
Capex per barrel per day Plateau Production
Based on the ultimate recovery of a field and the total CAPEX, an interesting yardstick can be constructed. The ultimate recovery is used to estimate the plateau production rate. The CAPEX is divided by this number of barrels (per day).
Unit Technical Costs (UTC)
The sum of the capital costs and operating costs can be divided by the number of barrels produced to give a unit cost. If the costs are discounted first and the barrels left as they are, we get the (PV) Unit Technical Costs (UTC). Some people argue that the value of the barrel in the future is less than today. They like to discount the barrels as well and then calculate the UTC'. Clearly, the latter is higher, because we divide costs by less barrels. We prefer the simpler UTC. Whatever happens to the revenues over time will be calculated anyway using oil price scenarios or assumptions in a detailed evaluation.
The UTC is often used by decision makers as a yardstick for a first rough screening of projects. Experience with the prevailing technical costs in a certain operating environment (e.g. North Sea) may be expressed in a range of UTC
Ultimate recovery per well
As well costs generally form the larger part of development expenditure, it is interesting to know how many wells are required to deplete a given amount of recoverable reserves. This depends on the flow rate of the wells and their lifetime. Reservoir engineers may work out what the ultimate recovery per well is. For instance, drilling of infill wells could be an option in an already producing field. Then each infill well could be economically evaluated. The cost of the well should exceed the value of the barrels that can be recovered from it. Ultimate recovery per well is again another yardstick that is encountered in economic evaluations.
When a successful exploration well is tested the first indications are obtained about how prolific the discovery is. Some wells do not flow at all and have to be pumped straight from the beginning. That means high UTC (see above). At the other extreme there have been discoveries that produced over 100,000 b/d. In such case only few wells will drain a field. What is almost as important to know as the recoverable reserves is the "well initial" production rate, a stabilized sustainable production rate that can be used for the economic analysis. Each well will show a decline, depending on reservoir conditions. From the well initial and assumptions about speed and shape of decline the number of wells that are required to drain a field in an optimal way can be determined, apart from more complex reservoir engineering considerations. In turn this allows estimates of CAPEX to be made.
Well production is a function of the viscosity of the oil, the temperature of the reservoir, hence depth, the "drawdown", i.e. pressure differential between the formation and the borehole/tubing, permeability, and the "skin factor" a measure of the damage by drilling to the formation, that may reduce the inflow into the well. Translated into factors a geologist might be able to estimate for a prospect, we get the following proxies: API gravity, depth and porosity.