LONDON (Reuters) – How low must oil prices fall before production starts to level off and even decline to rebalance the market?
There is no straightforward answer because it depends on so many factors most of which are uncertain or not observable.
These include the depth and duration of price falls; expectations about the extent and timing of any future price recovery; drilling and completion costs; wellhead prices and hedging programmes.
But any discussion about the outlook for production needs to start with an understanding of the lifecycle of an oilfield and the distinction between breakeven and shut-in prices.
Shut-in prices refer to the minimum wellhead price operators need to continue producing from a hole which has already been drilled and completed and is in production.
Prices at the wellhead must be sufficient to cover the ongoing costs of operation and maintenance, including pumping and artificial lift, as well as water, gas and steam flooding and other stimulation measures for older reservoirs.
Shut-in prices are as low as $15 per barrel in North Dakota’s Bakken, according to North Dakota’s Department of Mineral Resources. Elsewhere, however, operating costs and corresponding shut in prices are much higher.
For example, across the United States there are around 400,000 stripper wells each producing less than 10 barrels of oil per day (the average is 1.8 barrels). But in total they produced three quarters of a million barrels per day in 2012, according to the Interstate Oil and Gas Compact Commission.
Most of these stripper wells rely on surface pumps (the famous nodding donkeys) or more modern downhole submersible pumps. In addition they require surface separation facilities to remove water, dirt and gases from the oil before it can be sold, all of which cost money to run.
Stripper wells are not the only expensive form of oil. California’s aging fields require the injection of massive amounts of water, gas and steam to maintain their pressure and push the remaining oil deposits towards the wells. The crude must then be separated from enormous amounts of water.
In 2009, California’s operators injected 500 million barrels of steam and almost 1.4 billion barrels of water into declining fields to produce 230 million barrels of oil.
To make matters worse, more than half of the state’s production is heavy oil (with an API gravity of less than 20 degrees). Heavy crude sells for much less than light-oil markers such as WTI and Brent.
Oil sands in Canada and enhanced oil recovery schemes in Texas and Louisiana also have high operating costs linked to their need for steam or carbon dioxide injection.
All these high-cost forms of oil production are increasingly vulnerable to being shut in as wellhead prices in the United States tumble below $50 per barrel (and in some cases now below $40 per barrel).
Shut-in prices are only relevant for existing wells. New wells must cover their full life-cycle costs, including drilling, completion and operating costs, plus an acceptable rate of return, before a production company will authorise drilling.
Breakeven prices are typically much higher because the cost of drilling and completing a well is enormous. Drilling a hole thousands of feet into the ground can cost from $2 million to $12 million per well, depending on depth, horizontal length and geology, with fracturing and other completion costs on top.
North Dakota’s Department of Mineral Resources put breakeven prices at between $30 and $75 in different parts of the Bakken in a presentation to state lawmakers. These are the prices producers must expect to receive at the wellhead before they will authorise drilling.
There are no precise measures for wellhead prices. The Department of Mineral Resources estimates wellhead prices by averaging WTI futures (which is the very best operators could hope to receive ignoring all transport costs) and posted prices (the worst operators would receive for spot sales on their property).