After all the talk of living within cash flow in the downturn, it appears E&Ps are beginning to walk the walk.

First-quarter 2016 financial results from U.S. onshore producers show an improving balance between capex and operating cash flow, the U.S. Energy Information Administration said (EIA) July 18.

“Although operating cash flow was the lowest in any quarter in the past five years, larger reductions to capital expenditure brought these companies closest to self-finance [when capital investment can be paid for entirely from operating cash flow],” EIA said.

The question is whether it will last. E&Ps in the most economic cores are likely licking their lips over current oil prices, though commodities are struggling to reach half of what they were two years ago. EIA studied 39 public U.S. crude producers operating in onshore fields. Collectively, the companies produce 30% of U.S. Lower 48 volumes.

As crude oil prices averaged about $45 per barrel (bbl) in the second quarter—a 34% increase from first-quarter 2016—E&Ps’ cash flow could improve and help offset declining revenue from lower production, EIA said.

On the eve of second-quarter 2016 earnings reports, analysts are looking at cash flow, efficiency and production. Some see more subdued production results compared to the first quarter.

David Tameron, senior analyst at Wells Fargo Securities LLC, said E&Ps will likely have muted to slight production beats in the quarter compared to big production beats in the first quarter.

“…Overall production will be more in line with guidance from reduced activity levels despite a much improved commodity environment,” he said.

Despite a solid first quarter, 2016 production was the first year-over-year decline in crude oil and other liquids production for many companies in the past five years. Falling production would likely reduce revenue and cash flow absent an increase in crude oil prices.

Other specters haunted producers, including how they will respond to increases in price and whether they can hold onto cost reductions created through efficiencies and price cuts by service companies.

“We expect to hear that service costs were down again during the second quarter, although management conversations indicated we are reaching a bottom,” Tameron said.

E&P investors are skeptical that E&Ps can maintain the 50%-75% of cost reductions that they claim are attributable to efficiency gains in 2016, said Thomas R. Driscoll, an analyst at Barclays.

“We believe continued efficiency gains next year—fewer casing strings, the substitution of slickwater for gel fracks, better water-handling costs and more—will match or exceed service cost increases,” Driscoll said. While management teams will continue to talk about capital discipline, Tameron said some companies could privately be preparing to ramp up production.

“Expect Street focus to continue to be on 2017 capex and potential ramp scenarios … along with well results in Stack/Scoop and Delaware,” he said.

Wells Fargo projects that E&P cash flow and capex will align in second-half 2016. In 2017, cash flow will rise 42%, compared with 27% of capex. That equates to an outspend of 7%, “which is well below historical levels; and therefore there is room for our 2017 capex figures to be biased upward,” Tameron said.

While spending in past years was so capital intensive that it required external financing, balance sheets are healthier now, and budgets could begin to climb.

Driscoll said E&P companies generally spend cash flow, and he’s not convinced producers are willing to sit idle.

“The industry delivered strong production and operating costs in the first quarter without increasing spending,” Driscoll said. “We believe E&P companies may walk a fine line when addressing capital spending on second-quarter calls—but companies are staffed and eager to raise spending.”

However, he noted that many companies provide pro-forma growth forecasts or “core asset” growth figures that muddy the true underlying economics of the business.

“We estimate that the industry [based on current cost structures] needs about $55-$60 oil to deliver zero growth within cash flow and about $65 oil [WTI] to deliver corporate returns on new spending that approximate a high single(digit cost of capital,” he said.

Barclays’ price assumptions are $58/bbl in 2017 and $70 in 2018.

As for the itch to drill, a sharp reduction in drilled but uncompleted (DUC) wells could bring on as much as 135,000 barrels of oil per day (Mbbl/d) by mid-to-late 2017.

Darren Barbee can be reached at dbarbee@hartenergy.com.