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Diamondback Adds 14th Rig to Fleet; Talks Latest Well IPs

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   |    Monday,November 12,2018

Diamondback Energy reported its Q3 2018 results.

- Q3 production of 123 MBOEPD - up 9% from 2Q18 and up +45% YOY

• Increasing full year 2018 production guidance range to 118.5 119.5 Mboe/d, up 2% from prior guidance midpoint; implies 50% annualized growth at the midpoint from full year 2017 average daily production

- Adds Rig to Fleet; 14 Total: Operated 13 drilling rigs and five dedicated frac spreads during the third quarter of 2018. Following the closing of the Ajax acquisition, Diamondback assumed operations of one additional operated rig (14 total), and plans to maintain this cadence for the remainder of 2018. The Company now expects to turn between 170 and 175 gross operated horizontal wells to production for the full year 2018.

- Drilled 40 gross horizontal wells and turned 43 operated horizontal wells to production

• The average completed lateral length for third quarter wells was 9,638 feet.

• Operated completions during the third quarter consisted of 18 Wolfcamp A wells, 11 Wolfcamp B wells, 10 Lower Spraberry wells, two Middle Spraberry wells and two Second Bone Spring wells.

Ops / Latest Well Results

In Pecos County, Diamondback continues to achieve strong performance from operated completions targeting the Wolfcamp A. In Block 142 in the eastern third of our acreage, the Neal Lethco A 17-18 1WA was completed with a lateral length of 9,883 feet and achieved an average peak 30-day 2-stream flowing initial production ("IP") rate of 229 boe/d per 1,000 feet (89% oil). The State Neal Lethco 10-9 B 2WA, which commenced with a peak 30-day flowing IP rate of 173 boe/d per 1,000 feet (80% oil), went on to produce a peak 90-day flowing IP rate of 149 boe/d per 1,000 feet (79% oil).

Also in Pecos County, the Company recently completed two additional tests of the Second Bone Spring. The Black Stone State 1-12 B 1SB, with a lateral length of 10,081 feet, achieved a peak 30-day flowing IP rate of 121 boe/d per 1,000 feet (91% oil). The Stewart 28-21 Unit 1SB, after commencing with a peak 30-day flowing IP rate of 124 boe/d per 1,000 feet (85% oil), went on to achieve a peak 90-day IP rate of 103 boe/d per 1,000 feet (84% oil).

In the ReWard area of the Delaware Basin, Diamondback recently completed a two-well pad targeting the Wolfcamp A. The Nokota 19 DODT 1WA and 2WA, completed with an average lateral of 10,090 feet, produced an average 24-hour IP rate of 292 boe/d per 1,000 feet (74% oil). The Jane M Graves A 3WA, which commenced with a peak 30-day flowing IP rate of 217 boe/d per 1,000 feet (81% oil), went on to achieve a peak 90-day IP rate of 191 boe/d per 1,000 feet (80% oil).

In the Delaware Basin, Diamondback has recently begun testing the use of 100% local sand after closely monitoring offset activity and results. The Company recently implemented the use of 100% local sand with all three of its frac crews in the Midland Basin and has realized a ~$60 per lateral foot reduction in well costs relative to Northern White sand pricing from the first quarter of 2018. Additionally in the Delaware Basin, Diamondback is assessing the economic benefit of substituting diesel use with natural gas by running one rig and one completion crew with dual fuel capabilities. If successful and economic, Diamondback has five rigs and two completion crews with dual fuel capabilities in its current fleet.

In the Midland Basin, Diamondback has taken over operations from ExL, which recently completed a three-well pad targeting the Wolfcamp A. The UL Comanche A4144 Unit was completed with an average lateral length of 7,807 feet and produced an average peak 30-day IP rate of 166 boe/d per 1,000 feet (93% oil).

2024 Development Plan

Category	2023	2024 Est. Initial	Updated 2024 Guidance	%Difference (2023 vs 2024)
Total Capital Expenditure($mm)

Production Daily Equivalent(boe/d)
Production Oil(bbls/d)

 Click here for More Planned 2024 Activity