Some E&Ps are radically slowing down and pushing back completion of new wells as they hit upon a realization: They’re too prolific for their own good.

For the week ending March 27, U.S. commercial crude storage added an additional 4.8 million barrels (bbl) to already record high commercial stocks. In April, storage was at 471.4 MMbbl, soaring above the pre-2015 high of 399.4 MMbbl in April 2014.

Enter contango. Prices are up as much as $12 for delivery a year from now compared to what oil would fetch in May, said Randall Collum, managing director of supply side analytics for Genscape in an April report. For now, companies in the Eagle Ford, Bakken and Permian Basin are sitting tight.

Despite oil industry forecasts of production growth, some U.S. E&Ps have heeded the call to slam on the brakes. Cabot Oil & Gas (NYSE: COG), Chesapeake Energy (NYSE: CHK), EOG Resources (NYSE: EOG), SM Energy (NYSE: SM), Apache Corp. (NYSE: APA) and Anadarko Petroleum (NYSE: APC) alone have announced that they are deferring 845 well completions.

Operators are slowing down in the Eagle Ford, Bakken, Wattenberg and Permian Basin in hopes of higher future prices.

“The crude oil contango market in the U.S. has created a massive incentive to store oil, and while traditional storage hubs reach record high levels operators look to their own wells as an avenue to store until commodity market conditions improve,” Collum said.

Continental Resources (NYSE: CLR) has said they have the ability to “defer a significant amount of activity to await a better commodity price environment and lower oil field service cost.” After the first quarter of 2015, the company deferred 25% of its completion activity in the Bakken.

Deferring the completion of wells makes economic sense, Collum said. Companies save money while banking on the forward curve.

The impact of these deferrals, were they to come online in the same month, would be about 373 Mbbl/d of oil and 528 million cubic feet of gas per day (MMcf/d) of gas.

“Using a rough rule of thumb that the first 12 months of a new horizontal well averages approximately 50% of first full month initial production, the impact over 12 months of production would be approximately 68 MMbbl of oil and 96 Bcf of gas,” Collum said.

The effect of deferrals varies by play.

In the Eagle Ford, EOG is positioned in the core of the play. Even with its stellar history, the current commodity pricing makes returns marginal. Payback is 46 months with an Internal Rate of Return (IRR) of 16% if forward curve prices hold, or never. At a $45 WTI price, IRR is -2%.

For SM Energy, its position in the Bakken is just outside of the heart of the play. SM’s Gooseneck play is in the shallower portion of the Bakken, north of the Brockton-Froid Fault and their Raven/Bear Den play is in what Genscape refers to as the McKenzie/Williams Core.

“In the current commodity environment, well investment for SM Energy’s Raven/Bear Den play is estimated to never pay back, whether considering a fixed $45 WTI/$2.80 HH, or the increasing prices of forward curve,” Collum said.

Even at the higher realized prices of the forward curve and crediting a 20% savings on the completion portion of the spend yields a payback period of 5-8 years and IRR of 6%-7%.

“SM Energy appears to be choosing to drill because they are currently drilling efficiently, and to ramp down and then ramp back up that capability may ultimately be more expensive,” Collum said.