Landmen Economic Scenario

CAPL - Landmen Economics Scenario

Once a certain land area is identified as having petroleum potential, Landmen are called in to organize your company’s bidding on the parcels in the sale. Generally the economics needed to value the land for purchase will be fairly straightforward, with production declines, prices, capital and operating costs estimates based on regional averages and rules of thumb.

Example Scenario

In April’s Saskatchewan Land Sale there are 7.5 sections available that are adjacent to land your company currently owns. The land in question is adjacent to the currently owned Roncott field properties in South Central Saskatchewan and holds the possibility of oil production from the Bakken Zone. Your company has nearby infrastructure so it will be relatively inexpensive to fully develop the property. To determine your companies bid value at the upcoming land sale an economic evaluation of the expected development projects will need to be completed.

Petroleum Economic Components

Reserves and Production

The first thing to determine is the expected production capacity of any wells to be drilled on the new land. This production rate can vary widely and is best estimated using an analogy methodology to nearby wells (Average Initial Rate) combined with geological expectations for the area for greater or lesser amounts of pay.

To determine the reserves available under the land you want to purchase, reserve volumes and reservoir recovery factors are most reliably obtained from a geologist familiar with the area and reservoirs in question. Alternative reserve information can be gained from government or third party reports that determine estimated recoverable reserves and pool boundaries. If the land falls within the boundaries of a known pool or reservoir there is a greater probability that wells drilled on that land will produce.

Prices

After determining production you’ll have to estimate the price that your new oil can be sold for. Petroleum prices are extremely volatile and difficult to forecast, but to complete a valuation of the land available some semblance of a price forecast is needed. Price forecasts are determined in many ways and can be derived from many sources. There are exchanges worldwide that set prices for oil, gas, and assorted petroleum by-products. Given these market prices and other factors, oil & gas companies, consultancies and organizations create price forecasts. Most oil & gas companies have internal price forecasts that can be used as a basis for economic
evaluations. These forecasts are adjusted for the location of the wells and the quality of the oil & gas. I.e. the further you have to ship the product and the lower its quality, the lower the net price you can expect.

Combined with the production forecast, the price will provide an estimate of revenue for the projected wells.

Royalties

In return for producing from the reservoir, the owner of the oil will require some type of payment. Royalties are payments made to the owner of the oil directly out of the project revenue. In Canada generally the provincial government holds title to the minerals that are produced (crown royalties are paid), but in some cases the mineral rights can be held privately (freehold royalties are paid). These royalty percentages are complex to calculate but can be obtained from the Provincial government or are generally obtained from commercially available software packages or spreadsheets. These values are critical in determining the value of a project to a company.

Operating Costs

For every barrel of oil produced and for every piece of equipment at a well site, there are associated operating costs. These operating costs can be classified as production, well or other operating costs. Production costs are those costs that increase as the volume of oil produced increases. Well costs are those that are involved in maintaining the day to day operation of a well. Other costs include those costs that are not tied to the well or volume of oil produced.

Again a decent estimate of operating costs can be obtained from company operation engineers. As well, various consultancies do regional operating costs studies and can provide examples of typical operating costs for various types of wells.

Capital

Capital costs cover those expenditures that are used in the development and improvement of petroleum assets. This includes well exploration, development and facilities development costs. Estimates of capital costs can be supplied by company engineers or can be estimated based on historical costs for other similar wells in the area. Again many Canadian consultancies can provide examples of typical capital costs for wells around Canada.

Interests

Your company may not be interested or have the available cash to purchase 100% of the land that is available for sale. In this case the cost of the land could be split with one or more other companies. Ownership or working interests are used in economic evaluations to determine the share of income that a company can derive from wells drilled on that land. E.g. a 50% working interest on a property means that a company will get 50% or the revenue, be responsible for 50% of the capital and operating costs and, in the end, receive 50% of the cash flow. Ownership interests can be quite complex, involving multiple companies and interests ranging from royalty, or revenue, interests to interests based purely on net profit.

Cash Flow & Net Present Value (NPV)

Once production, prices, operating and capital costs and your company’s working interest in the project are forecasted, project Cash Flow can be calculated. After Tax Cash Flow is equal to revenue less royalties, operating and capital costs, and taxes. These cash flow values, once totaled over time, show the value of the project to the company.

NPV is a concept used to determine the present worth of a stream of future cash flows through what is called discounting. In oil & gas it is generally assumed that you can find investments that give a company a 10-15% return on investment after tax. This means that if the project you are investing in does not provide at least a 10-15% return on investment, or shows a negative discounted cash flow, you should find another project to invest in. Discounting the future After Tax Cash Flow of a project, using the minimum rate of return value (e.g. 15%), lets you know what the benefit to the company is above the minimum return that is expected. (This is a very quick explanation of discounting and NPV. More can be learned about these concepts from any
decent basic finance or economics textbook.)

Scenario Conclusion

Once you obtain all the needed values to determine the expected cash flow for the Roncott purchase you can determine the amount that you would spend at the land sale. If you discount the Roncott project cash flow at 15% and the value is greater than zero, the project is worth pursuing, assuming that your original assumptions were correct. The net present value after discounting is the maximum amount that you would spend to purchase the land rights at a land sale. (This assumes that you did not include land costs in the economic evaluation).

Petroleum Economic Resources

Now that you have covered the introductory concepts involved economic evaluations you will want to try some evaluations on your own. There are many tools available to do petroleum economics, including Merak’s Peep and Web Peep applications. You can try Web Peep out on the Internet and work through a more detailed petroleum economics tutorial at http://webpeep.merak.com/. Merak also provides training in petroleum economics in conjunction with Sproule Associates of Calgary. Learn more about Merak, its software and services on the Web at http://www.merak.com/ or by calling (403) 294-4300.

The Author: Todd Kuipers is the Team Leader - Web Development at Merak, the industry leader in petroleum economic software.