Too Soon? Some E&Ps Rev Up Capex Despite Low Prices

The conundrum facing the U.S. E&P industry may not be when to fire up the engines but how to throttle them back.

Even with lower capex, companies are beating guidance. Oil prices have gradually recovered as U.S. shale supply began to fall in earnest before taking a bad turn in July.

As oil held steady around $46 per barrel (bbl) in July and even commanded $50/bbl at times, operators modestly added rigs to fields. So far in the second quarter earnings season, capex is making a comeback.

Amidst a fragile recovery, could it be too soon? That was the worry of the U.S Energy Information Administration (EIA), which said in late July that more stable oil prices contributed to more drilling.

Even as WTI prices have retreated to roughly $40/bbl, several E&Ps are ramping up with more rigs and opening drilled but uncompleted (DUC) wells.

Although declines from existing wells are expected to result in a net decrease in production, increased drilling and higher well productivity could partially offset the decline, the EIA said.

Anadarko Petroleum Corp. (NYSE: APC) pumped out record production in the U.S. Gulf of Mexico (GoM) and the Delaware and Denver-Julesburg (D-J) basins despite keeping capex steady.

In an earnings call, Anadarko CEO Al Walker said July 27 that $60 oil is possible by the end of 2016 and that the company would ramp up production if that happens. Anadarko ended the second quarter with nearly $1.4 billion of cash will ramp up production if the price is right, Walker said.

“The cautious approach we outlined for oil price recovery at the beginning of 2015 has played out much as we anticipated,” Walker said. “It now appears U.S. oil supply peaked at around 9.6 million barrels per day (MMbbl/d) and we expect it to bottom out around 8 MMbbl/d.”

With global demand exceeding expectations, Walker said he sees “$60 per barrel moving into 2017.”

In the same frame of mind, EQT Corp. (NYSE: EQT) is beginning to ramp up for 2017 with an accelerated drilling program, according to a report by Charles Robertson II,an analyst at Cowen & Co.

“EQT plans to spud an additional 63 wells, 33 Marcellus wells and 30 Upper Devonian wells,” he said. “Capex remains unchanged at $1 billion as lower well costs are offsetting increased drilling activity.”

Other companies are moving forward with money.

Clayton Williams Energy Inc. (NYSE: CWEI) said it expects to see production for fiscal 2016 average up to 13,900 barrels of oil equivalent per day (boe/d), an increase of 1,000 boe/d from prior guidance.

“Capital expenditures for 2016 are currently expected to total approximately $105.5 million, up $36 million from prior guidance,” the company said Aug. 3.

In an Aug. 4 earnings call, Mel G. Riggs, president of the Clayton Williams, said the company plans to use a single rig to drill 10 wells, including eight in Wolfcamp A and two in Wolfcamp C. He said he expects to complete seven by the end of the year.

“We’re increasing our guidance on capex,” Riggs said, “but we’re offsetting that somewhat by the sale of a non-op position in Glasscock County, Texas, with $19.5 million hopefully from that sale.”

The divestiture will have minimal impact to production, he said. Clayton Williams holds a 65,000 net acre position in the southern Delaware Basin.

Remarking on the company’s recent struggles and newfound production boost, Riggs said the company had held on to its assets “through this downturn, one of the worst. It rivaled anything from the 1980s.”

So far in the second quarter, capex is up an average 4% while production is up 1%, largely associated with NGLs, said David Tameron, senior analyst at Wells Fargo Securities LLC in an Aug. 3 report.

Efficiency is also producing higher new-well oil production per rig. Through July 2016, oil wells averaged 796 barrels per day (bbl/d) in the Bakken region, 983 bbl/d in the Eagle Ford and 470 bbl/d in the Permian, according to EIA.

Each of the three major oil pays is averaging more per well than in 2015. Average Eagle Ford wells, for instance, have increased production by 226 bbl/d since 2015.

Tameron said that E&Ps were expected to ramp up as they attempted to stabilize or had off production declines heading into 2017. While Tameron still sees the logic in the approach, the recent downturn in WTI hasn’t moderated kicking up production or openly announcing higher capex.

“Instead, those companies that have planned on ramping have indicated that they will stick with their plans, and a number of crude/NGL exposed companies have actually raised capex,” Tameron said. “We all suspected they would raise capex eventually, but just thought $40/bbl would have tempered it. And maybe the scary thought is that it has.”

In the second quarter, earnings have shown gas production, not crude, beating expectations.

Cimarex Energy Co. (NYSE: XEC) estimates total production volumes for 2016 to average 980-1,000 million cubic feet equivalent per day (MMcfe/d), up from 2015 production of 985 MMcfe/d. Higher volumes were based on gas.

Oil volumes are expected to be 28% of total volumes and gas 47%. Cimarex said it would increase its exploration and development capex to $750 million in 2016, up from previous guidance of $650 million to $700 million. The additional capital will be used primarily to fund further drilling in the Meramec Play and to accelerate well completions in the Permian Basin and Midcontinent region.

The company has also increased its operated rig count to five rigs from four for the remainder of 2016.

Cimarex will be more actively completing its DUCs in the second half of 2016, including 11 of 17 net Permian DUCs and 28 of 29 net Midcontinent DUCs, said Jonathan D. Wolff, analyst at Jefferies.

“XEC has emphasized in previous quarters that it is not a big fan of playing the ‘DUC game’ and prefers to only drill wells with the intention of completing them,” Wolff said.

As Cimarex and other companies start additional drilling, how much service companies will charge is another variable to consider.

“Second-quarter service and well costs are down form first quarter levels,” Tameron said. But service company pricing may start to plateau.

“Only a few E&Ps have mentioned anything resembling signs of upward pressure,” he said. “Cost structures across the space have come in below expectations, which in theory continues to lower breakeven threshold.”

However, the cost of sand per foot used for proppant continues to climb.

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