U.S. oil and gas in the near term and the impact on Colorado

Anybody who has being paying attention to oil and gas markets knows opinions on future oil and gas prices are all over the map.

Add opposing perspectives about ongoing cost re-structuring in the business – due to operators being technologically better or operators able to demand discounts from oil field service suppliers ­– and it’s easy to understand there are a lot of independent variables that affect the “health of the industry.”

Since the devastating drop in prices in late 2014, we’ve been through two short price cycles – an uptick in prices due to OPEC’s announced production cuts in late November, and a more recent drop in prices tied to growing crude inventories. 

The effect of oversupply was immediate, as the pricing chart (adjusted for inflation) indicates. We’ve recovered from the December 2015 lows, but is this recovery equivalent to a late 1986 recovery – range bound for nearly 12 years – or is it a 1998 type recovery, which was the start of fantastic upcycle in the oil and gas business?

Given that the U.S. Geological Service (USGS) estimated that 20 billion barrels of recoverable oil are yet to be produced from the Permian Basin in West Texas/Southeast New Mexico, that operators in Alaska have drilled wells that together show nearly 4 billion barrels of recoverable oil, and that operators around the world are adding reserves, it’s clear that oil supply will be there to meet demand if prices provide the margins necessary to justify drilling.

The industry still has latent productive capacity that can come online when prices are “right.”

The map below shows all the wells that have been drilled, but which have not been completed (commonly referred to as drilled but uncompleted wells, or DUCs). They represent pending oil and gas production that can be brought online reasonably fast when prices rise to acceptable levels for operators.

Drillinginfo’s Rig Analytics calculate there are 5,319 DUC wells in the U.S. The number of DUCs in Colorado is 572, or just over 10 percent of the national total. Most of Colorado’s DUC wells are concentrated in the Niobrara play, which makes sense because these wells are all horizontal, which have high completion costs (hydraulically fractured wells needing expensive pressure pumping services, large volumes of proppant and water). Of the wells in the Niobrara play, almost all are in Weld County.

The number of active rigs in Colorado is modest compared to the white hot Permian basin. 

The reason for this is that both the subbasins in the Permian-Delaware and Midland – have multiple productive reservoirs that can be horizontally drilled once the primary target zone has been drilled and depleted. By drilling there now, while costs remain relatively low, and in an area where oil and gas transportation infrastructure is robust, operators can position themselves to hold multiple producing reservoirs. Other producing oil and gas basins generally do not have this kind of favorable geology.

Drillinginfo’s ProdCast subsidiary has calculated break even prices for all basins in the US, and calculates that DJ-Wattenberg (Niobrara) wells break even at prices around $40/barrel.

Posted prices for DJ oil are, as of March 29 $40.57 per Shell Marketing.

So Niobrara operators are more or less at break even pricing, which would explain why a lot of wells are drilled, but not completed… who wants to only break even on an investment per well of $4 million to $6 million?

And they are at break even at current cost levels, which are depressed due to oil field service companies heavy discounting to generate sales and remain in business.

Although most operators have managed to get highly discounted pricing from oil field service suppliers, this will not continue if prices begin to rise and demand for things like proppant and pressure pumping services increase. Once these rising prices start negatively impacting margins, the pressure will be to drill or complete as few wells as are needed to HBP acreage or meet corporate cash flow/debt obligations.

So what’s the near-term outlook for Colorado oil and gas?

The Permian will probably be the only basin that will see continued growth in well starts. Other basins — including the DJ — will be relatively static in drilling activity, and each will start adding rigs only when the local posted price slightly exceeds breakeven levels. If a company needs a 20 percent return on its investment, Colorado operators would probably like to see a sustained period of $48 to $50 /bbl pricing before they would be comfortable in committing funds to an aggressive drilling program.

The picture may be a bit cloudy if Colorado operators have hedged their production at prices seen in the recent price spike. This can artificially support drilling activity, but since hedges have a relatively short life the pricing gains from hedging cannot be expected to sustain a long-term development program.