The transition to U.S. oil targets by the exploration and production (E&P) industry now is complete, with operators more able to concentrate on drilling efficiencies and the higher capital outlays required, according to Canaccord Genuity.

Capturing the “sustained price advantage of crude oil” over dry gas took E&Ps about two years to complete, according to analyst John Gerdes. E&Ps now have an opportunity to improve operational efficiencies, such as pad drilling, and gain “some relief in oilfield service pricing pressure.” The field efficiencies are needed in part because E&P capital “intensity” already has increased by about 5% year/year.

Over the past two years E&Ps faced higher costs and production delays above ground, as oilfield service operators shifted work crews and equipment from gas to oily formations. The decline in NGL prices also is adding to higher costs as more operators fine-tune their strategies. But it’s a given that oilfield development costs more to develop than the gas fields.

“Since ’10, the industry pivot to liquids development has coincided with a 40% increase in E&P capital intensity,” said Gerdes. In finding and development costs, “E&P capital intensity has increased from $22.00/bbl to $31/bbl. Correspondingly, industry capital allocation by product has roughly inverted to 60% liquids and 40% gas.”

The median E&P development capital intensity now is about $5.20/Mcfe ($31.00/boe), which is 5% lower than in 2012, but which accounts for oil and gas operators. The method of financial accounting associated with acquiring, exploring and developing new reserves, or the DD&A (depreciation, depletion and amortization) rate, increased about 10% a year from 2010 through 2012, as E&Ps acquired more oil-prone acreage. However, the average rate was about one-half of the “actual increase in capital intensity,” which coincided with higher oil development costs.

With dry gas and NGL drilling no longer a priority, Canaccord expects gas production to “stagnate or decline” this year, based on its coverage portfolio.

“Natural gas development capital intensity is $2.75/Mcfe, and cash operating expenses [opex] are $1.25/Mcfe, equating to an all-in cost structure of $4.00/Mcfe,” said Gerdes. “Given a 25 cent/Mcfe E&P company gas price discount to Nymex, the current Nymex-normalized natural gas development cost structure is $4.25/Mcfe.”

Meanwhile, capital intensity for liquids development now averages $37.50/boe and cash opex is $17.50/boe, equating all-in costs of $55.00/boe. “Given an $11/boe E&P company liquids price discount to Nymex, the current Nymex-normalized liquids development cost structure is $66.00/boe.”

According to Gerdes, unleveraged cash expenses are projected to average $2.40/Mcfe ($14.50/boe) in 2013, which is 10% higher year/year. And the bigger emphasis on oil development is clear from widening margins. Assuming Nymex prices of $4.00/Mcf gas and $93/bbl oil, “E&P cash operating margins should expand 8% and gross profit margins should increase 4%.”

Under Canaccord’s coverage universe, the E&P shares reflect New York Mercantile Exchange (Nymex) prices of $4.85/Mcf natural gas and $80/bbl oil, “the commodity prices that deliver a market return on equity capital,” Gerdes said. “Long-term, we anticipate Nymex $5.25 gas and $90 oil prices, implying a positive sector risk/reward (almost 25% upside) with oil-weighted E&Ps having greater upside than gas-weighted peers.”

On Canaccord’s list of favorite “buy-rated” names are several with lots of onshore oil potential: Anadarko Petroleum Corp. (Wattenberg, Eagle Ford); Cabot Oil & Gas Corp. (Marcellus); Comstock (Eagle Ford); and Eagle Ford-focused EOG Resources Inc., SM Energy Co. and Sanchez Energy Corp. E&Ps on “hold” include gas-heavies EQT Corp., Range Resources Corp. and Southwestern Energy Corp. On the “sell” list is SandRidge Energy Inc., which is “overvalued in our view given questionable Mississippian [Lime] commerciality and under appreciation of the company’s long-term capitalization challenge.”