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Permian Pure-Plays Diamondback, Laredo, RSP Raise Production Guidance

Diamondback Energy Inc., Laredo Petroleum Inc., RSP Permian Inc., a trio of Permian Basin pure-play independents, went to town in the second quarter to improve their positions by ratcheting up efficiencies, with all three raising their 2016 production guidance.

The trio of Permian producers are part of the 2Q2016 earnings and projections covered in NGI's Earnings Call and Coverage sheet.

Diamondback Output Rises 23%

Midland, TX-based Diamondback, in partnership Viper Energy Partners LP, boosted its 2016 production guidance to 38,000-40,000 boe/d from 34,000-38,000 boe/d because of increased drilling and completion activity. Production jumped 23% year/year to 36,800 boe/d, while the high end of 2016 lease operating expense (LOE) guidance was revised to $5.50-6.25/boe from $5.50-6.50.

"Our strong well performance during the second quarter reflects our ability to exceed production expectations despite a reduced completion pace for the bulk of the first half of 2016,” CEO Travis Stice said during a quarterly conference call. “We added a fourth rig in early July and continue to evaluate adding a fifth rig if commodity prices strengthen.”

The company, long a Midland sub-basin player, in July spent $560 million to gain entry into its twin, the Delaware sub-basin of Texas (see Shale DailyJuly 13). Development in the new leasehold is to begin late this year, Stice said.

“The bigger story in the Delaware is the rate of change,” he said. “The operators over there have quickly optimized the lateral landing point. They've enhanced the completion techniques to make them more competitive. And I think...the opportunity for Diamondback to continue to do what we've always done, which is do accretive bolt-on acquisitions, is there.

“And while we don't talk specifically about what our acquisition activity is, I think it's reasonable to assume that, just like in the Midland Basin, Diamondback’s fingerprints will be all over the trades in the Delaware Basin as well.”

Diamondback expects to exit 2016 “in a position to achieve double-digit production growth in 2017 within cash flow assuming $55/bbl.”

The producer at the end of July was working four horizontal rigs and running two completion crews to work through its inventory of 20 drilled but uncompleted wells (DUC). The producer drilled 15 gross horizontals and completed 11 operated horizontals in the quarter, with the operated completions consisting of seven Lower Spraberry wells, three Wolfcamp A wells and one Wolfcamp B well.

“Production response from the increased activity is expected to begin during the second half of 2016, with the majority of the DUCs completed by the end of 2016,” Stice said.

Since Viper's initial public offering in June 2014, the partnership has acquired more than 2,100 net royalty acres for less than $270 million, he said. Production has risen since mid-2014 by 185%, with the potential drilling inventory increasing by nearly 200% and proved reserves up by more than 170%.

With a $168 million impairment charge related to depressed commodity prices, Diamondback recorded a net loss in 2Q2016 of $155 million (minus $2.17/share), compared with a year-ago loss of $212 million (minus $3.45).

Laredo Raises Original 2016 Guidance by 11%

Tulsa-based Laredo produced a company record 47,667 boe/d during 2Q2016, 73% weighted to oil and natural gas liquids. Anticipated production for 2016 has been increased to a range midpoint of 17.15 million boe, 11% higher than original 2016 projections.

The independent completed 16 horizontals between April and June, with an average completed lateral length of 9,700 feet. Ten of the wells reached their peak 30-day IP rates, averaging 1,147 boe/d, or 135% of the type curve. LOE in the period declined by 36% year/year to $4.43/boe.

CEO Randy Foutch credited the company’s trademark “Earth Model,” providing investments in “data collection, reservoir modeling, infrastructure, product takeaway and actual well testing,” that led to improved efficiencies and output. Laredo operated three horizontal rigs in the quarter, which drilled on average 990 feet/day from rig acceptance to rig release, an improvement of 66% from a year ago.

“These efficiencies have reduced the average number of days to drill a well by approximately 36% from the second quarter of 2015, even as the company has extended the majority of its laterals to 10,000 feet and longer,” Foutch said. “On average, the company’s well cost for 10,000-foot laterals in the Upper and Middle Wolfcamp that utilize optimized completions are approximately $6.3 million, but the company’s most recent costs are trending to the mid-$5 million level.”

Laredo completed 16 horizontals in the quarter, with average lateral lengths of 9,700 feet and peak IP rates averaging 35% above the type curve.

Laredo now is operating three horizontal rigs and anticipates completing 10 wells by the end of September, nine in the Upper and Middle Wolfcamp, with one in the Cline Shale.

“The wells are expected to have an average lateral length of 11,000 feet, including four that are at least 13,000 feet, as the company continues to benefit from its contiguous acreage position that enables the drilling of more capital efficient longer laterals,” Foutch said.

Laredo isn’t averse to adding more leasehold as it can. In early July it secured more rights to the Spraberry zone in Glasscock County, TX. The acreage, said Foutch, “perfectly fits our development model, which includes accommodating a production corridor, having fully processed Earth Model data, development of 10,000-foot or longer laterals, and Laredo with a high working interest.

“In fact, development of this acreage has an additional cost reduction advantage. We own five sections of surface within this block, enabling Laredo to drill its own water wells and access water for completions at very low cost. The combination of production corridor and water cost savings are expected to lower the cost for a Spraberry, Upper Wolfcamp or Middle Wolfcamp 10,000-foot horizontal to a range of $5.8 million to $5.9 million.”

Laredo reported a net loss of $71.4 million (minus 33 cents/share) in 2Q2016, from a year-ago loss of $397 million (minus $1.88). Total revenue declined to $146.7 million from $182.3 million.

The producer also recognized more than $6.4 million in cash benefits from Laredo Midstream Services LLC field infrastructure investments. Transported volumes on the Medallion-Midland Basin pipeline system increased to 99,039 b/d from year-ago volumes of 34,600 b/d.

RSP Intentionally Builds DUC Backlog for Flexibility

At Dallas-based RSP, production jumped 33% from a year ago and 7% sequentially to 26,400 boe/d. Eleven operated horizontals were completed in the Permian, with 10 in the Lower Spraberry and one in Wolfcamp A. It also completed one operated vertical well. IP rates in the Lower Spraberry exceeded 4,700 boe/d on average lateral lengths of 7,100 feet.

Based on results to date, expected 2016 production was increased by 10% at the midpoint to 26,500-28,500 boe/d. Capex also was boosted to $285-315 million.

Like Diamondback and Laredo, RSP continued to block up its core leasehold, bolting on acquisitions that year-to-date has totaled $55 million.

"Even with a moderated capex pace in the second quarter, RSP increased production while maintaining a lean cost structure and strong capital efficiency,” CEO Steve Gray said. “The increased investment during the second half of 2016 will position us for a higher growth profile in 2017."

Production volumes in the quarter were 73% weighted to oil, 12% to liquids and 15% to natural gas.

The company operated two horizontal drilling rigs in the quarter and one full-time completion crew. It began the quarter with 20 operated DUC horizontals and exited the quarter with 19.

“We had intentionally built up a sizable backlog of drilled but uncompleted wells to provide us with flexibility to operate at a lower rig count,” Gray said. Earlier this year, he noted, management had said that $45/bbl oil represented the “inflection point for both the returns on our wells become more attractive and adding a rig begins to de-lever the company.”

When oil moved above $45, RSP contracted a third drilling rig for 3Q2016 for one year.

“We continue to have flexibility, however, with our rig cadence as our two existing rigs come off contract in early 2017,” he said. “So should oil prices deteriorate, we can easily elect to moderate our drilling pace in the first quarter of next year.”

RSP recorded a quarterly net loss of $9.8 million (minus 10 cents/share), versus a year-ago loss of $5.5 million (minus 7 cents).

Operations chief Zane Arrott said RSP is on track to complete 52-56 horizontals this year after completing 22 in the first six months.

“We expect to exit the year with eight to 12 operated wells waiting on completion,” he said. RSP is now drilling and completing 7,500-foot laterals for about $5 million each.

“For the last few quarters, we have tested numerous high-density completion designs,” Arrott said. “ We have systematically varied a number of key drivers in the stimulation design, such as cluster count and configuration, sand volume and mesh size and diverter agents...

“Ultimately, our goal with this testing is not only to increase productivity and estimated ultimate recoveries per well, but also to increase per section or per acre recoveries. As we experiment with tighter spacing, we plan to simultaneously decrease the potential interference between neighboring offset wells. Our focus is to more intensely stimulate near the wellbore...to increase our recovery of oil in place within a smaller rock volume, allowing us to meaningfully increase well density within a given development unit. The results we have seen today support this approach.”

RSP’s fracture design a year ago was 210-foot spacing on fracture stages, four clusters at about  1,600 pounds/lateral foot of sand.

“All of this year, we have gone through a number of variations of that,” Arrott said. “We really haven't changed the stage length, but we have been increasing the number of clusters, and we have increased the pounds per foot.

I think we've been as high as 2,100 pounds, but that's just been one-off or two-off, we're probably 1,950 pounds right now…But we don't want to give out our exact recipe, so we're going to be fairly vague about it.”

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