Commodity prices will tell the 2015 tale in the dry gas ArkLaTex as early season expectations of a cool winter in the eastern United States warm the hearts of natural gas-oriented operators. That warmth is tempered somewhat by the growing chill of falling crude oil prices, particularly for operators in the Tuscaloosa Marine Shale (TMS) and other nascent East Texas liquids-rich plays.

At least one significant TMS player is ratcheting back capital expenditures to the lower range of guidance as 2014 comes to a close. Goodrich Petroleum Corp. (NYSE: GDP) will cut capital spending from $97 million in the third quarter 2014 to $60 to $75 million to close out the year. Total capital expenditures of $325 million in 2014 are projected to fall to the $200 to $225 million range in 2015 with all spending allocated to a two- or three-rig program in the TMS.

Hart Energy’s market intelligence survey found crosslink gel is the preferred completion method in the deep dry gas basins of the ArkLaTex and in the liquids-rich Tuscaloosa Marine Shale. Slickwater fracks are still predominate in the Barnett Shale.

The survey captured observations from vendors working the Barnett, Haynesville and Tuscaloosa Marine shale plays. Those respondents report that regional demand in the heavily dry gas oriented region had been static with the exception of increased activity in the Tuscaloosa Marine Shale (TMS).

Outside the TMS, respondents project demand will remain flat in the dry gas plays over the next 90 days. Those observations came despite an improved outlook for natural gas on the basis of revised early season forecasts calling for cooler weather in the eastern U.S., which prompted a brief rally in December 2014 natural gas futures above the $4.06 per million Btu marker in early November.

Currently, the supply of pressure pumping fleets in the ArkLaTex is sufficient to meet regional demand with ready access to nearby crews and equipment in adjacent basins. Survey respondents estimated regional capacity at 600,000 hydraulic horsepower (HHP).

“Lots of former Haynesville fleets went elsewhere in Texas,” a mid-tier oil and gas producer told Hart Energy surveyors. “But many providers will supplement this area as needed with fleets from the northern Eagle Ford, or southern Oklahoma.”

A mid-tier service provided noted: “We have seen most crews in the region tied to specific commitments from current operators so any increased demand may require bringing in new fleets to accommodate new projects.”

At least one pressure pumping service provider sold its fleet and left the ArkLaTex region in the last 90 days.

Well metrics reported by survey respondents vary across the region. In the TMS, respondents cited an average vertical depth of 11,200 feet with horizontal lateral length at 8,835 feet. On average, operators employ 22 stages per well in the play.

Metrics are similar as far as stage count for the Haynesville Shale, where average vertical depth is listed at 9,000 feet with an average horizontal length of 7,335.

In the dry gas Barnett Shale, operators are averaging 19 stages on wells that feature lateral lengths of 5,500 feet. The reported average vertical depth of a Barnett Shale well was 7,000 feet, according to survey participants.

Sand volumes include 300,000 pounds per stage in the Tuscaloosa Marine Shale (TMS) on spacing that ranges from 250 to 350 feet per stage, or an average of 290 feet among survey participants. TMS sand volumes exceeded 400,000 pounds per stage for select operators experimenting with enhanced completions. On average, survey respondents pegged average proppant per well at 5.75 million pounds regionally, mostly natural sand but supplemented with both resin-coated sand and/or ceramics to overcome the high pressure, high temperature downhole environment in the deeper wells.

As is the case elsewhere, operators are gradually pushing lateral lengths and adding more sand per stage in predominately plug and perf completion methodologies. The methodology is similar in deep, high-pressure dry gas wells such as the Haynesville, and in newer liquids-rich targets such as the TMS.

Multi-well pads are common in the region currently, though survey respondents pegged the average number of wells per pad at two.

Pricing for stage varies across the region, ranging from $75,000 in the Barnett Shale to $133,000 in the TMS. The deep, high-pressure Haynesville was just below the TMS at $128,000 per stage. Survey respondents were split evenly on whether pricing would increase or stay static.

“Pricing has been rising with tight sand supply and increased sand volumes,” according to a mid-tier oil and gas operator. “Acid is high. The cost has just risen, but now the price of oil has everyone unsure.”

Separately, three fourths of drilling contractors participating in a parallel survey reported demand for rigs has been steady with little change quarter-to-quarter, while remaining respondents said demand was down and rigs had been shipped to other areas for work. Nonetheless the rig replacement cycle continues with larger oil and gas operators ordering newbuild 1,500 horsepower AC-VFD rigs. Pricing ranges from $24,200 per day for AC-VFD 1,500 AC-VFD rigs and $23,500 for diesel electric SCR units.

To date, operators have expressed guarded concern about commodity pricing. One operator said his company could make their acreage work at $80 oil.

Contact the author, Richard Mason, at rmason@hartenergy.com.