One of the barometers of upstream activity—pressure pumping utilization—sank in 2012, as low natural gas prices choked drilling in some U.S. shale-gas plays. For E&Ps, the lower frac pricing that resulted was a boon in offsetting poor gas prices.

At press time, both E&Ps and fracing companies reporting fourth-quarter earnings were generally more optimistic than in 2012. There was general speculation that a bottom in frac pricing had been reached.

Simmons & Co. International, Houston, said in a late February report that the fracing market had tightened due to frac companies’ newfound capital discipline coupled with the “relentless, inexorable service intensity of unconventional resource development.” They said emerging plays such as the Cline, Utica and Tuscaloosa Marine shales could provide a home for idle/new equipment.

The analysts surveyed E&Ps as well as pressure pumpers. Their discussions confirmed a “healthy inventory” of drilled but uncompleted wells. Their caveat for pressure pumpers: adding capacity in response to a more robust market could destabilize the delicate supply/demand framework.

“What is clear from the fourth-quarter earnings calls is that few, if any, of the public companies (pressure pumpers) intend to add additional new horsepower in 2013,” they said. E&Ps and service firms are emerging from retrenchment in 2013, but cautiously.

Drilling has rebounded a bit in the Marcellus and other gassy plays, with E&Ps capitalizing on the jump in natural gas prices from an average $2.37 in first-half 2012 to $3.40 in fourth-quarter 2012, the analysts said. Encana plans to lift its Haynesville rig count from two to five rigs this year.

E&P procurement teams Simmons visited believe pricing has bottomed. But as term contracts expire, some continue to negotiate declines. One E&P reported renegotiating the contract for one of its term fleets in the Eagle Ford down from $170,000 to $180,000 per stage, to $95,000 to $105,000. A private frac company in the Mississippian Lime play said his per-stage pricing is now $35,000 to $40,000, half of what it was a year ago (based on spot market frac pricing). The same company said its $350,000 bid for a recent job on a well was undercut by $100,000, said Simmons analysts.

In the thirst for cost efficiencies, drawing attention from both E&Ps and fracing companies , especially in the Bakken, is dual-fuel technology. The Energy & Environmental Research Center at the University of North Dakota, in partnership with the North Dakota Industrial Commission and Gas Research Council, the U.S. Department of Energy and several major oil and gas partners, studied using associated petroleum gas for fueling diesel engines powering drilling rigs in North Dakota.

The 47-day demonstration showed a fuel-related savings of nearly $60,000 over the 47-day period (more than $1,200 per day) because of the lower value of associated petroleum gas relative to diesel, and a reduction in overall air emissions.

The Simmons analysts called dual-fuel-capable engines a theme for 2013, allowing frac companies to run their fleets on both diesel and natural gas. They look for E&Ps to drive the transition, because fuel costs often are about 10% of a frac work ticket.

Frac companies are testing similar technology. Simmons said Patterson-UTI Energy Inc. has an agreement with Pennsylvania General Energy to convert 16 frac units to dual fuel—7% natural gas and 30% diesel—paring fuel costs for the fleet to 25% of the cost had it run solely on diesel. “PGE intends to drill 35 to 40 Marcellus wells in 2013 and expects to save 750,000 gallons of diesel a year, or 55% of the diesel in its fracing operations,” the analysts said.

Overall, Simmons looks for E&P capex in 2013 to hold steady with 2012, with WTI in the mid-$90s and gas prices in the low $3s. It estimates $59.4 billion in drillbit capex for calendar-year 2013, compared to $65.5 billion in 2012. Its E&P coverage universe also has nearly $55 billion in cash and undrawn lines of credit, with E&Ps tapping the equity window.

The analysts expect service intensity to continue, with an “explosion in horizontal-directed work in 2012” in the Permian Basin, where leading E&Ps are testing 10,000-foot laterals. In the Eagle Ford, EOG is increasing lateral lengths from an average of 4,000 feet to 5,500 feet—requiring more stages and more proppant volumes. The analysts said COG recently completed a 35-stage frac in the Marcellus, and in the Tuscaloosa Marine shale, Encana plans to boost proppant per stage from 360,000 to 600,000 pounds.

With that intensity will come higher service costs for E&Ps.