Results from the third quarter show Permian Basin pure-plays Diamondback Energy Inc., RSP Permian Inc. and Laredo Petroleum Inc. feeling bullish heading into 2017.
After reporting strong results in the second quarter (see Shale Daily, Aug. 11), all three independents reported double-digit production growth rates from their West Texas operations in 3Q2016, and all three discussed adding rigs as soon as the fourth quarter.
Diamondback To Add Sixth, Possibly Seventh Rig In 2017
Diamondback produced 44,900 boe/d in 3Q2016 (73% weighted to oil), a 22% sequential increase and a 32% increase year/year. And the Midland, TX-based exploration and production (E&P) doesn’t plan to slow down anytime soon.
“Diamondback remains optimistic on a commodity price recovery and has continued to re-accelerate the pace of activity by adding a fifth rig in October and plans to add a sixth rig in 2017 on a recently closed Delaware Basin acquisition,” CEO Travis Stice said during a 3Q2016 conference call, adding that the company “could potentially add a seventh rig in 2017, should conditions warrant.”
In July, Diamondback agreed to a $560 million deal to grab 19,180 net acres in the Permian’s Delaware sub-basin (see Shale Daily, July 13).
Stice said the E&P expects to deliver 30% production growth in 2017 at current strip prices “at or near breakeven cash flow.” Diamondback set its 2017 production guidance at 52,000-58,000 boe/d, with plans to complete 90-120 gross wells at average lateral lengths of 8,500 feet.
Diamondback operated an average of four rigs during the third quarter, drilling 17 gross horizontal wells. The E&P ran two completion crews and completed 21 operated horizontal wells in the quarter, 10 in the Lower Spraberry, seven in the Wolfcamp B, two in the Wolfcamp A and two Middle Spraberry wells.
Diamondback drilled two wells in Glasscock County and one in Martin County with average laterals of 10,980 feet over 11.5 days on average to spud to total depth. The company drilled two wells in Midland County with laterals exceeding 13,000 feet.
The company reported results from a two-well Wolfcamp B pad completed in Glasscock County. The wells had average laterals of 10,050 feet and produced a 30-day flowing two-stream initial production (IP) rate of 1,425 boe/d per well (85% oil). A second two-well pad targeting the Wolfcamp B was completed with an average 30-day IP rate of 1,067 boe/d (85% oil) per well. The laterals for those wells averaged 8,106 feet.
A three-well pad in Howard County completed during the quarter targeted the Lower Spraberry, Wolfcamp A and Wolfcamp B with average laterals of 9,725 feet. Its Reed 1A 1WA and Reed 1A 1WB produced peak 24-hour IP rates of 2,149 boe/d (89% oil) and 1,801 boe/d (90% oil), respectively, with the Lower Spraberry well producing 797 boe/d (89% oil).
Diamondback said it expects to complete all of its remaining drilled but uncompleted (DUC) wells by the end of 2016.
Drilling costs declined during the quarter, with lease operating expenses (LOE) falling to $5.37/boe, compared with $7.08/boe in the year-ago period. Total cash operating expenses averaged $9.15/boe for the quarter, versus $11.49/boe in 3Q2015.
Realized prices averaged $42.11/bbl for oil, $2.37/Mcf for natural gas and $13.76/bbl for natural gas liquids (NGL). Year-ago prices averaged $44.12/bbl, $2.67/Mcf and $10.22/bbl, respectively.
Diamondback reported a net loss of $600,000 (minus 3 cents/share), compared with a net loss of $237.5 million (minus $2.40) in the year-ago quarter.
RSP Permian Increases Production 24% Year/Year
Dallas-based RSP saw production increase 24% year/year to 29,800 boe/d, which also represented a 13% sequential increase. The E&P has upped the midpoint of its 2016 production guidance 5% to 28,500-29,500 boe/d based on increased well productivity. The third quarter production mix was 73% oil, 10% natural gas and 17% NGLs.
RSP said it closed on $19 million in bolt-on transactions during 3Q2016, bringing the nine-month 2016 total to $62 million.
CEO Steven Gray said in a 3Q2016 earnings conference call that RSP is negotiating to add a rig to its Midland Basin operating area in early 2017, bringing its running total to four.
Two rigs will see their contracts roll off early next year, opening up the possibility of reduced drilling costs if RSP can take advantage of current market rates. These savings should offset higher costs from enhanced completions using “larger proppant loads, increased diverter usage and more perforation clusters,” he said.
In October, RSP announced deals totaling $2.4 billion to buy up acreage in the Delaware by acquiring Silver Hill Energy Partners LLC and Silver Hill E&P II LLC (see Shale Daily, Oct. 14).
“The Silver Hill footprint is highly contiguous and well-suited for long lateral development, and with seven currently producing zones, the asset is significantly de-risked,” Gray said. “These assets also came with a sizeable production base of approximately 15,000 boe/d…We see significant upside in the assets as we bring our operational expertise to the Delaware and further delineate the various zones using longer lateral development on multi-well pads.”
Gray offered his outlook for RSP as works to bring its operating experience in the Midland over to the Delaware acreage it expects to acquire on closing of the Silver Hill transactions.
“In the next six months or so, you’ll see us focusing our attention foremost on building out infrastructure to accommodate a more full-scale development program,” he said. “Silver Hill has established excellent relationships with service providers, landowners and mineral owners, and we will build on that foundation.
“As we begin constructing enhancements to our infrastructure, we anticipate accelerating the pace on our Midland Basin properties by adding an additional rig and keeping the existing two horizontal rigs in place in the Delaware,” Gray said. “We will then accelerate on the Delaware properties towards the second half of 2017. As we approach the end of 2017, we expect a balanced rig program between the Midland and Delaware basins.”
RSP operated three horizontal rigs and one completion crew during the third quarter. The company drilled 10 operated horizontal wells and completed a total of 17 operated horizontal wells in the third quarter, including 11 in the Lower Spraberry, three in the Wolfcamp A and three in the Wolfcamp B.
RSP completed its strongest well to date in the Wolfcamp A, the Kemmer 4217 WA, which produced at an initial rate of 254 boe/d per 1,000 lateral feet in its first 30 days. The Kemmer well was drilled in the westernmost portion of its Wolfcamp A acreage, pointing to the potential of the western acreage position, RSP said.
The E&P drew down its DUC inventory from 19 operated at the start of the quarter to 12 exiting the quarter. It entered the quarter with 24 non-operated DUCs and ended the quarter with 18.
Realized prices for the quarter, excluding hedges, averaged $34.19/boe, including $42.60/bbl for oil, $2.27/Mcf for gas and $10.82/bbl for NGLs. That’s compared with $36.52/boe in the year-ago quarter, including $44.84/bbl for oil, $2.27/Mcf for gas and $8.72/bbl for NGLs.
Lease operating expenses for the quarter came in at $4.67/boe, down from $6.08/boe in the year-ago quarter.
RSP posted net income for the quarter of $985,000 (1 cent/share) from net profits in the year-ago quarter of $8.97 million but a significant improvement over 2Q2016, in which the E&P posted a net loss of $9.8 million.
Laredo Posts Record Production
Tulsa, OK-based Laredo posted a company record 51,276 boe/d of production (46% oil) in the third quarter and raised its full-year 2016 expected year/year production growth to 10%. LOE declined to $3.85/boe in the quarter, down 13% sequentially and 37% from the year-ago period.
“Third quarter results again demonstrated the benefits of the company’s prior strategic investments in data and infrastructure,” CEO Randy Foutch said. “Continued refinement of Laredo’s multivariate Earth Model analysis of data collected throughout eight years of development activity has enabled the identification of multiple landing points per zone and optimized completions driving recent results, on average, more than 30% above type curve in the Upper- and Middle-Wolfcamp and Cline shale zones. Field infrastructure investments have helped lower unit LOE almost 50% since the beginning of 2015.”
Foutch said Laredo planned to add a fourth rig in mid-November while working within its existing $420 million capital program for the year.
In the third quarter, Laredo completed 10 horizontal development wells with average working interest of 98%. Seven of those wells boasted laterals greater than 10,000 feet and completions of 2,400 pounds/lateral foot.
Laredo reported a 1,639 boe/d peak 30-day IP rate from its G. Schwartz 17-8-1NC well in the Cline Shale, which had a lateral length of 9,900 feet and used 1,800 pounds/lateral foot. Laredo also reported early results from the Sugg-A-208-209-1SU and Sugg-E-208-207-1NM wells targeting the Upper- and Middle-Wolfcamp, respectively. Those wells, which used proppant loads of 2,400 pounds/lateral foot and had lateral lengths of around 7,500 feet, have produced at 161% and 140% of type curve thus far, the E&P said.
Laredo “has implemented a managed drawdown protocol that both limits initial choke settings and restricts the amount the choke is opened as the well produces.” The approach could limit IP rates but is designed “to enhance primary fracture conductivity, thereby improving production and recoveries over the life of the well.”
“We kind of had this view all along that the emphasis on the 24-hour IP in the first two weeks or three weeks and 30-day accelerated IP was probably not what we wanted to do,” Foutch said. “We’ve talked about it in the past that we wanted to see significant data before we really call. What we are trying to do is make sure that on our flowbacks we are allowing the well to flowback at a rate such that…we attempt to make sure that where we put the proppant, it stays there.
“We are trying to make sure that we are not changing any of the relative perm curves near wellbore. We are trying to make sure that we get the maximum benefit over time for our completions.”
Laredo has guided for 4.7-4.9 million boe in 4Q2016 production. Revenues for the quarter totaled $159.7 million, up from $150.3 million in the year-ago quarter. Realized prices averaged $39.10/bbl for oil, $11.54/bbl for NGLs and $2.07/Mcf for natural gas, compared with year-ago prices of $42.88/bbl, $10.36/bbl and $2.01/Mcf, respectively.
Laredo reported a net income for the quarter of $9.5 million (4 cents/share), compared with a net loss of $847.8 million (minus $4.01/share) in the year-ago period.
© 2020 Natural Gas Intelligence. All rights reserved.
ISSN © 2577-9877 | ISSN © 1532-1266 | ISSN © 2158-8023 |