Introduction to Oilfield Economics: Payout
Posted by D Nathan Meehan January 21, 2011
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Evaluation Criteria and cash flow analysis

Payout

In this and some following blog entries, many of the common measures of cash flow are defined and illustrated.  Perhaps the most common economic measure and one of the simplest is “payout.”  Also known as payback time, it is defined as the length of time required to recover invested capital and expenses.  In other words, it is the length of time to reach a cumulative cash flow of zero. Payout makes the most sense for economic projects in which there is an initial negative cash flow followed by a period of (in aggregate) positive cash flows.  Payout comes in several versions including discounted payout.

In an example we will revisit several times during this and following blog posts, an initial investment is followed by a series of monthly cash flows dues to oil production. This case can be found on the website of the Society of Petroleum Evaluation Engineers (SPEE)[1] along with a number of guidelines that are relevant to reserve reporting, oil and gas property evaluation and economic appraisals. Some of the common assumptions in the case include:

Initial oil rate 200 BOPD
Investment $1,000,000
Decline rate 0.3 year -1
Hyperbolic exponent 0.5
Constant oil price 25 $/bbl
Net revenue interest 85%
Working Interest 100%
Operating costs 2000 $/month
Severance taxes 10%
as of date 1/1/2000
evaluation date 1/1/2000

From these assumptions we can calculate monthly cash flows. These monthly cash flows can be accumulated as in the following figure.

this graph shows npv versus cos for the drill and farmout case

In this example a visual inspection of the cash flows shows that the payout is in approximately ten months. A close examination of the monthly cash flows shows that the cumulative cash flow at ten months is a negative $6,401 while at the end of month eleven it is a positive $78,717. Common practice for economic evaluators is to interpolate (linearly) which would result in a payout of just less than 10.1 months or 0.84 years. Payout can be expressed in any common time units.  It is common practice in many software programs to linearly interpolate payout at the finest level of timing used in the evaluation. If that is annual, the linear interpolation assumption could introduce a noticeable error. Payout measures are inherently imprecise because the actual cash flow timing is almost never precisely correct. While a well may produce daily, operators rarely get paid daily for that production. Many analysts (including the published SPEE example) ignore the variation in days/month and leap year. Others take these into account. Those that do account for them should not use fixed expenses as $/month. Payout should not be reported to an excess number of significant figures.

After tax calculations of payout are common place as are “discounted” payouts. Unless otherwise noted by the analyst, “payout” is generally assumed to be a before-tax undiscounted measure. Company procedures and practices will dictate consistent approaches to calculating each of these economic parameters.

Payout seems simple; however, there are a host of circumstances that lead to inconsistencies in its calculation. These include:

  • Questions about when to start the clock
  • Situations with multiple future investments including multiple times when the cumulative cash flow reaches zero
  • Situations where the cumulative cash flow is always positive
  • Incremental evaluations

The initial investment in the prior example was assumed to be at “time zero” and the SPEE example doesn’t specify the investment to be a drilling cost. It is possible that a well or field producing 500 BOPD could be purchased on a given date and then be generating cash for the account of the owner the very same day. In the case of drilling a well, a certain amount of time is required to drill, complete, equip and begin producing the oil. In more complex situations an operator might have the following series of expenditures:

  • Obtain offshore studies and “spec” seismic
  • Invest months of geological and geophysical time to analyze and identify potential blocks in an upcoming offshore bid round
  • Bid on several blocks, winning at least one
  • Conduct a 3-D seismic study on the newly acquired block(s) and conduct further Geological and Geophysical (G&G) studies along with engineering studies for drilling, completing and producing any potential discoveries
  • Drill one or more exploration wells
  • Drill appraisal wells as needed
  • Test appraisal wells as needed
  • Conduct further studies and sanction a development project
  • Build and install an offshore platform with corresponding facilities. Drill complete and equip the necessary wells
  • Construct oil and/or gas pipelines or alternative methods to transport products to market.  This may include onshore facilities such as crude stabilization or even electric power generation to monetize natural gas in areas without ready markets
  • Start production

It is entirely possible that the time period for this project could run in excess of ten years prior to any positive cash flows being generated. For preparing economics of a bid for a lease sale, it is typical to use as ‘time zero” for the date the bid will be submitted; prior expenditures are usually ignored. The logic in this approach is that the prior expenses are part of more general ‘exploration costs’ such as employing internal expertise. However, once the first exploration well is to be drilled, it is not unusual to “reset the clock” and recalculate payout at the time the exploration well is to be drilled. This is often repeated at the major capital investment steps. The logic is that prior expenditures are “sunk costs” and that the current decision is being made on the basis of the immediate decisions to be made. In such cases, after tax calculations must correctly incorporate the tax implications of legitimate alternatives such as abandoning a block and writing off prior expenditures[2].

A general rule is that the appropriate evaluation time is at the beginning of “substantial” expenditures. In the offshore case this could have been the lease bonus or the exploration well. In the case of construction of a facility such as a gas processing plant, it would generally not be until construction actually commenced and would depend on the terms of the contract stating when payments are due. In all cases, the analyst should clearly state when payout starts and the assumptions involved.

In many cases a moderate sized project is commenced to fully evaluate a technology or to generate early cash flow while additional opportunities to develop more of the field mature. One example is a thermal recovery project in which a few patterns are steamflooded under existing permits and full scale development might not be permitted (or possible) for a few years due to regulations, available fresh water, processing facilities, etc. If the steamflood project is being evaluated, the first project might very well pay out prior to expenditures taking place for the larger project. Payout can be stated for the small project and an incremental approach can be used to show the larger project payout, resetting the clock to time zero when those large expenditures commence.

Payout is rarely the determining or sole economic criteria in complex or large projects. It is best suited for simple projects such as a workover in which the investments are relatively small and the characteristics of the resultant cash flows are familiar to the decision makers. Payout’s major weakness is that it gives decision makers no idea how much money the project actually makes. Other weaknesses include only a simplistic piece of information about timing.


[1] SPEE “…was organized exclusively for educational purposes and to promote the profession of petroleum evaluation engineering, to foster the spirit of scientific research among its members, and to disseminate facts pertaining to petroleum evaluation engineering among its members and the public.” http://www.spee.org/index.html

[2] The handling of both the financial and tax calculations vary by country and often by the specific circumstances of the operator.

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