Oil and gas shale production economics are creating an era of low cost energy in the US. But how do you decide if drilling one well is any more profitable than drilling another well next door or in a different basin? Just like with any other investment opportunity you compare net present values (NPV) and internal rates of return IRR). Today we continue our rundown of shale production financial return calculations with a review of variable production costs and NPV.
In the first episode in this series (see Drilling) we discussed “unconventional resources” and conventional hydrocarbon drilling then reviewed the technologies developed by the late George Mitchell and his team to produce unconventional shale resources. In the second episode (see Shale Production Economics – Part 2 – Drilling and Completion Costs) we introduced the eight input factors for our model of production economics and provided example values for drilling and completion costs. In part 3 we explained four techniques to forecast initial production (IP), decline rate and estimated ultimate recovery (EUR) for a shale gas well (see Shale Production Economics Part 3 – Estimating Well Production). These production parameters determine the rate of return for a well. Unconventional shale wells are characterized by high IP rates and rapid decline rates,but the high early production rate provides drillers with a rapid return on their investment, which makes these plays so attractive.
In this series we are modeling the economics of shale production with reference to a specific example – the Haynesville Shale. We use the Haynesville because it is a dry gas formation, meaning that only natural gas (“mostly methane”) is produced. That allows us to model the production economics without having to delve into the complexities associated with wet gas (including NGL) or combined crude and gas liquids. These liquid hydrocarbons are, of course very important to many US shale plays today, but once you understand the economic returns on a dry gas well then the liquids produced from wet gas or oil wells can be viewed as an additional uplift dimension to the basic model.
In this fourth episode we will look at the variable production costs associated with drilling and producing a shale gas well. Together with our earlier analysis of fixed costs (drilling and completion) as well as production estimates, we will then have the data we need to calculate NPV and IRR. These measures facilitate economic comparisons between different wells.
Variable Production Costs
Well drilling and completion are fixed costs of production. Once the well is producing gas, there are a number of variable operating costs. These variable costs may be broadly grouped into two buckets - operating expenses and royalties and taxes. Conceptually these are all expenses directly associated with operating the well, are generally variable, and are thus quantified on a per produced volume basis in $/MMcfd. In the Haynesville formation, our analysis indicates that typical operating costs are about $0.80/MMcfd.
Operating expenses are direct costs associated with operating each individual well together with the gathering system that connects the wells to a processing plant or pipeline interconnect. We can generally split the operating expense of any well into two components as follows:
- Lease operating expenses:
- Labor cost for both the operation and the maintenance of field equipment.
- Water disposal costs: a great deal of water can be produced from the well along with natural gas. Like the flow back that occurs during hydraulic fracturing, produced water is regulated by the Environmental Protection Act (EPA) and Clean Water Act (CWA) provisions. In accordance with these regulations an operator must properly dispose of produced water.
- Fuel costs to operate wellhead equipment and pumps. Variation in fuel costs can have a significant effect on operating expenses.
- Property taxes - depending on where the lease is located, the operator may have to pay an Ad valorem tax, which is a tax on the value of the property. In this case it is the value of the equipment used to operate the well.
- Other expenses include materials and supplies used to operate the well, and insurance.
- Gathering and transportation costs:
- Pump costs to move gas from the wellhead to field treatment facilities
- Extraction of natural gas liquids (not necessary for dry gas wells like those in the Haynesville).
- Gas treatment including any combination of dehydration (removal of particulate water), removal of carbon dioxide - CO2, and sweetening (removal of hydrogen sulfide - H2S) each at a corresponding cost.
Cost of compression to move gas from gathering system and treatment facilities onto market transportation pipelines that operate at a much higher pressure than gathering systems.
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