HOUSTON—Natural gas prices are stuck, oil volatility is sticking around and E&Ps continue to forge ahead as service companies cave to lower costs.

Acquisitions and mergers may continue as well, Wood Mackenzie analysts said May 15 at a media presentation with Lower 48 Upstream analysts. But many have been shelved, said R.T. Dukes, research director, Wood Mackenzie.

Noble Energy Inc.’s (NBL) $3.9 billion merger with Rosetta Resources Inc. (ROSE) announced on May 11 follows the massive $70 billion merger of Royal Dutch Shell Plc (RDS.A) and BG Group Plc in April.

Dukes said acquisitions will be driven by strategic motives—for instance a company deciding it wants exposure to more than one oil resource play in the U.S.

“If you look at the Permian, that’s where we’ve seen a lot of deals in the last week and probably where you’ve seen the least consolidation as well,” Duke said. “So you’re seeing operators getting more comfortable with the upside in the Permian.”

Overall, non-acquisition spending is set to be lower in the U.S. core tight oil plays as companies focus on core areas and reduced per-well costs will offset spending cuts.

Capital spending in the largest plays has been reduced by $36 billion from 2015-18 as tight-oil operators focus on optimization and hunt for cost reductions.

While oil prices have done a belly flop in 2015, costs are down by 15% with drilling, rigs and proppant leading the way.

For instance, drilling mud costs have come down an average of 30%, to about $338,000 from $481,000 in 2014.

One uncertainty will be the ‘stickiness’ of cost reductions as oil prices rise, said Benjamin Shattuck, senior analyst, Wood Mackenzie.

Cody Rice, senior analyst, said that recent price recovery could still bounce and “maybe lead us down to the downside.”

However, the past eight months of gut-wrenching price drops appears to be behind the industry.

“I don’t think we see that kind of volatility,” he said.

North American gas struggles will continue as prices are unlikely to surpass $4 over the next five years while production grows, Dukes said.

The oil shale industry, however, has been helped by deflations in service cost and drilling and completion (D&C) efficiencies that are changing as fast as the price of oil, Shattuck said during his presentation.

In the Permian Basin, for instance, unit cost reductions and drilling efficiency, as measured by feet per day, is on the rise.

“We expect U.S. tight oil production to grow to 5.8 million barrels per day (MMbbl/d) by 2020,” Shattuck said.

However, tight oil production is already slowing, companies are high grading across the supply chain and breakeven changes are a moving target in plays and subplays.

The workhorses of the shale revolution, the Bakken in North Dakota and the Eagle Ford in Texas, are now being eyed for long-term reliability. Together, the Bakken and Eagle Ford account for nearly two-thirds of U.S. tight oil production, about 2.5 MMbbl/d.

The Eagle Ford’s breakneck pace is cooling. However, productivity continues to improve. In 2014, E&Ps completed 13% more wells than 2013.

The Permian’s Wolfcamp promises upward of 25,000 remaining locations with about 5,000 of those offering top net present value (NPV).

The Eagle Ford still has a massive inventory, with about 20,000 locations, but only a few thousand among the top NPV.

Nevertheless, the Eagle Ford has considerable running room within high-return parts of the play, Garrett said.

And by July 2016, Eagle Ford IP rates should be up 33%, breakevens down by as much as $15/bbl and costs down 16%, Rice said.

Still, there is a wide variation in the breakeven points for massive resources.

“Proceed with caution,” Rice said.

Contact the author, Darren Barbee, at dbarbee@hartenergy.com.