What it means
A drilling crew bores a hole from the surface to the depth of the reservoir, lines it with steel pipe, and then opens it up so the oil or gas can flow to the surface. Because the hole meets the reservoir at one point, a vertical well draws from only a limited area.
The advantage is cost and simplicity. Vertical wells need less specialised equipment and less time, so a company can drill many of them for the budget of a single complex well, which suits fields where the resource is thick and easily reached.
Horizontal wells can run sideways through a thin layer of rock for a long distance, and so they expose far more of the reservoir. They cost much more to drill, but may produce much more, which is why they are common in shale formations.
The decision is a trade-off between upfront spending and expected output. For finance teams, the key measures are the drilling and completion cost, the expected production over time, the price of the commodity and the operating costs.
Production from a new well usually starts high and declines steeply, so forecasts must allow for a decline curve and not assume flat output. Investors and lenders also look at risk.
A dry or disappointing well still costs money, and the price of oil and gas can fall after the money is spent, so companies often drill in stages and review the returns from each batch. The accounting treatment is worth knowing.
Costs of drilling and completing a well are usually capitalised (recorded as an asset) and then written off over the life of the production, rather than charged to expense at once. The method used, and how the costs of unsuccessful wells are treated, affects reported profit and should be read in the notes to the accounts.
In practice
Real-world examples.
Example
A small independent producer in Texas drills ten vertical wells into a shallow, thick formation. The low cost per well lets it spread risk across many holes, and one disappointing well does not threaten the programme. The strategy is cautious, but it keeps capital spending in line with cash coming in.
Example
A lender reviewing a loan to an energy company asks for the forecast output of each vertical well and its decline rate. The analyst finds that the borrower's forecast assumes no decline, and asks for a more realistic schedule. The lender's request is a useful discipline, since a flat forecast can hide a weak project.
Example
A gas company compares drilling a single vertical well with drilling a horizontal one on the same site. Management selects the vertical option because the reservoir is thick, the spend is lower, and the commodity price outlook is uncertain. The board approves the plan with a clear review point after the first year of production.
Formula
Calculation
Payback period = well cost / annual net cash flow
A company drills a vertical well at a total cost of $3,000,000. After operating costs and royalties, the well is expected to generate net cash flow of $1,000,000 a year. Payback = 3,000,000 / 1,000,000 = 3 years. A horizontal well in the same field might cost $8,000,000 and generate $2,500,000 a year, giving a payback of 8,000,000 / 2,500,000 = 3.2 years, so the cheaper vertical well pays back slightly sooner here.Case study
Seen in the real world.
Red Mesa Energy is an illustrative, fictional company that holds the rights to a mature oil field. Its engineers proposed five new vertical wells at $2,000,000 each, giving a total budget of $10,000,000.
The finance director built a model with each well producing $1,000,000 of net cash flow in its first year, falling by 30% a year after that. Even with this decline, the wells repaid their cost in under three years in the base case.
The model also showed that a fall in the oil price of 30% would extend payback to more than five years. In this illustrative case, the board approved two wells first, reviewed the results, and committed the rest of the budget only after the early wells performed as forecast.
Watch out
Common mistakes.
- Assuming a well will produce at its initial rate for years, when output usually declines sharply after the first months.
- Comparing wells on drilling cost alone, without considering how much each one is expected to produce.
- Ignoring the cost of closing and cleaning up a well at the end of its life, which is a real obligation.
Questions
People also ask.
Is a vertical well always cheaper than a horizontal one?
Usually yes, per well, but a horizontal well may be cheaper per unit of oil or gas recovered if it produces much more.
Why do some fields use only horizontal wells?
In thin layers of rock, such as shale, a vertical well touches only a small slice of the resource, so a horizontal well is needed.
What is a decline curve?
It is a forecast of how a well's output falls over time, and it is the basis for estimating the cash a well will earn.
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