Close to 100 additional rigs will be moved to the U.S. onshore through 2014, with about half directed to the Permian Basin, according to an analysis by Tudor, Pickering, Holt & Co. (TPH).

Jeff Tillery, who is head of research for oilfield services, and Matt Portillo, who directs exploration and production (E&P) research, offered the firm’s insight about domestic oil and natural gas markets in a conference call last Friday. The forecasts are based in part on information gleaned from recent third quarter conference calls, as well as anecdotal evidence compiled from the operators.

The big takeaway is that Permian Basin activity continues to improve. And dry natural gas drilling, in specific areas for specific drillers, is becoming fashionable once again.

A pullback in the oil price likely will mean a pullback in some onshore basins, said Portillo.

“While we are expecting a relatively bullish outlook for areas like the Permian, a lot of the other plays are going to be relatively flat on a rig count perspective with well count really driving capex higher…”

It’s important to note, said Portillo, that some of the biggest onshore operators, including Chesapeake Energy Corp. and Encana Corp., are cutting capital expenditures (capex) “pretty dramatically year over year, with that potentially offsetting some of the increases from the large and midcap names…

“We do think some of the high-level commentary from the E&P perspective is bullish on capex, but is very company-specific. We think there are definitely companies where the capital budgets are moving lower.”

Some pure play natural gas drillers have decided to once again get back into the game.

“What really looks pretty interesting about gas is that, as we’ve kind of moved through the quarter here, unlike in the beginning of the year when there was a discussion around what gas prices were needed to accelerate rig counts, a lot of the heavily levered gas E&Ps, the pure play gas E&Ps, have really just decided that they have rigs, and if they have capital, gas drilling what they’re going to be able to do,” Portillo said.

More gas drilling is on the drawing board for Ultra Petroleum Corp. and WPX Energy Inc., he said. Ultra management recently highlighted how efficiencies helped cut well costs in the gassy Pinedale Anticline (see Shale Daily,Nov. 6). WPX also is drilling some mega gas wells in a portion of the Niobrara formation (see Shale Daily,Oct. 28).

Those gas drillers and others are “adding dry gas rigs to the extent that their balance sheets will take on the incremental leverage to the extent that they have cash flow coming through,” Portillo said. “It’s an interesting phenomenon. Even though the forward strip has come down for dry gas, there are actually dry gas rigs being added.”

Oil differentials are not a concern, yet. “We’ve seen a huge move in oil differentials, not only in the Permian Basin, but also in the Bakken…Some of those we do see as temporary, particularly the Permian, where we think differentials will start to improve as the refinery runs increase.

“The Bakken is probably going to take a little bit more time to improve…It will take time for the rail capacity to move incremental volumes to the East Coast.” Most of the operators see the oil differentials “as more of a temporary nature. If it remains more structural, that could start to affect drilling programs and where they’re going to go on a forward basis…”

Blowing down the well completion backlog is a huge priority, said Portillo.

“There’s been a big ramp this year in terms of completions overall by E&P operators, in some cases. Chesapeake is probably the most aggressive on this front as they try to remove their backlog, but they have significantly completed their well count versus their current drilling plan. I think that will continue on a go forward basis, particularly in the dry gas plays.”

TPH estimates that there are about 300-350 wells in the Utica Shale to be completed. Another 400-500 wells still need completion in the Marcellus Shale, evenly split between the wet and dry gas windows, Portillo said. Another 200-300 Eagle Ford wells also need to be worked out of inventory.

“I think as we look across those three plays particularly, you have about 1,000 wells that are going to be worked down from a completion perspective. Once that gets worked off, you may actually see a drop on the completion front as operators move more toward the steady state drilling program within their capital budgets.”

Tillery said, “there’s absolutely been a step higher in terms of completions focus and intensity…It really seems like a light switch went on kind of in the middle of the year, where we’ve seen a number of companies really amp up the volume of proppant used” to fracture and modify completion techniques on horizontal wells.

“Drilling efficiencies may feel like a tired topic but it’s something that is still very meaningful, and we think there’s a lot of room to run still,” Tillery said. “We’re probably not going to repeat the 18% efficiency gains of 2012, or the 15% efficiency gains of this year, but we certainly think next year is in the double-digits,” he said of drilling costs coming down.

About 10% of the onshore drilling activity is performed by international oil companies (IOC), 45% by public independents and the other 45% from privates, TPH estimates. By scrubbing the TPH coverage list, which is about two-thirds of the public independents, the spending level is forecast to be “in the high single digits, of maybe up to 10%,” he said.

IOC spending looks to be “relatively cautious or pessimistic, so we’re thinking spend levels for that group will be flat to maybe modestly lower for 2014.” There’s less transparency on 2014 spend by privates, but TPH estimates capex will be higher. Combined, the public and private E&Ps capex is forecast higher in the coming year, “mid to high single digits, 5-8%.”

However, the capex won’t be as freely distributed among different locations as it’s been in the past.

“Where incremental spend and where incremental rigs go to work from current levels, which is obviously lower than the year-to-date averages of 2013, we think around 50 horizontal rigs are set to be added in the Permian Basin,” said Tillery. The Bakken and Utica shales, as well drilling in south-central Oklahoma “all look to us to be up plus or minus 10 rigs from where we are today.

“The Eagle Ford, the Marcellus look flattish. The Mississippi Lime looks flattish. The Midcontinent, including the aggregate Wash plays, may be up marginally, but you roll all that together, and that’s how we get to our forecast of 4Q2014 U.S. rig activity up about 100 rigs from where we are today. That all adds up to only about a 2% increase year/year because of the downtrend we’ve been in over the course of 2013.”

Listening to executives discuss their plans for 2014, Tillery said most credit drilling efficiencies for growth. And in many cases, fewer rigs can complete more wells. However, “I think there’s no doubt the Permian is going to be up big year over year on the horizontal side…If we use 50 rigs of incremental horizontal activity, that’s up 20-25%, so that is a meaningful increase…That’s on a basis of a little over 200 horizontal rigs out of 1,100 total in the U.S.”

The “feel” about the rig count “is absolutely better than it was three months ago…As we went through the summertime, we had the land drillers all concerned” about a slowdown toward the end of the year, worried it would be a repeat of 2012, said Tillery.

Additionally, behind the scenes, BHP Billiton Ltd. scaled back on its U.S. onshore spend, which “pushed a bunch of rigs back onto the market. So you had good quality rigs looking for a new home, in addition to concern about declines in the year end.” But the market “is actually better than it was over the summer,” with more newbuilds coming onto the market to replace lower quality, less efficient rigs.