The US rig count dropped 12 units to 502 during the week ended Feb. 26, according to Baker Hughes Inc. data. While the decline is the smallest thus far this year, it represents the eighth straight weekly double-digit drop to begin 2016.
The total is the lowest since Apr. 30, 1999, a week after the 1998-99 downturn hit its bottom of 488. With additional losses in the coming weeks, the current count could dive to a level not seen in generations.
Financial services firm Cowen & Co. this week forecast an onshore rig count bottom of 375-400, possibly occurring in April.
Cowen & Co. noted that of the 32 exploration and production firms that, before this week, reported drilling and completion capex for 2016, a total of 19 have published planned rig count activity that altogether implies 51 units will be dropped.
“Assuming 15 rigs are cut per week, the rig count would bottom in mid-April,” the firm said. “Completion activity will lag rig activity supported by [drilled but uncompleted wells].
“We think this could put the bottom in completion activity sometime in the middle of [the third quarter],” it explained. “With a lower [third-quarter] exit rate, it would not be until [the fourth quarter] for reported revenues to actually bottom.”
Cowen & Co.’s tally of Lower 48 spending for independent E&P firms was down 53% as of the end of last week. Including majors, the firm expects capex to be down 39%.
“Interestingly, median consensus revenue for the onshore focused service companies are forecast to be down only 25%, suggesting yet another round of downward revisions,” it noted.
Fellow financial services firm Raymond James & Associates Inc. previously projected the overall US rig count to bottom at 400 in June (OGJ Online, Feb. 12, 2016).
Onshore, oil continue to drop
Onshore this week, the count fell 14 units to 473. Rigs engaged in horizontal drilling lost 19 units to 397, down 975 since a peak in BHI data on Nov. 21, 2014, and their lowest point since July 10, 2009. Directional drilling rigs edged down a unit to 47.
Two rigs began work offshore Louisiana, bringing the overall US offshore count to 27. Rigs drilling in inland waters remained static at 2.
Oil-directed rigs continued to pull down the overall count, falling for the 10th straight week. Losing 13 units to 400, the count is down 1,209 since its peak in BHI data on Oct. 10, 2014, and at its lowest point since Dec. 11, 2009.
The gas-directed count, which has been cut nearly in half since its last increase in December, rose for the first time since then, edging up a unit to 102.
Canada managed up upstage the US this week while taking its largest decline of the year. Down 31 to 175, the country’s overall count reflects a 26-unit dive in oil-directed rigs to 83 and 5-unit decrease in gas-directed rigs to 92.
Canada’s recent overall rig count low is 72 on May 22, 2015.
Eagle Ford count shrinking
Modest declines relative to recent weeks in the major oil- and gas-producing states were headlined by a 5-unit loss in Texas to 231, down 727 since a peak in BHI data on Aug. 29, 2008, and the state’s lowest count since the 1990s.
The state’s eighth consecutive week of losses was anchored by a 7-unit drop in the Eagle Ford to 47, down 212 since a peak on May 25, 2012.
During IHS CERAWeek in Houston this week, Scott Sheffield, chairman and chief executive officer of Pioneer Natural Resources Co. (PNR), said he believes the Eagle Ford’s overall rig count will soon shrink to 25, compared with 200 at the beginning of 2015 (OGJ Online, Feb. 25, 2016). The firm cut its count in the play to 0 at the beginning of the year.
Meanwhile, PNR is concentrating all 12 of its rigs from midyear onward in the northern Spraberry-Wolfcamp (OGJ Online, Feb. 11, 2016). “The [Permian’s rig count] hasn’t dropped that much because it’s mostly oil and the returns are much, much better,” he explained, noting there are 70 rigs in the Midland basin and 70 in Delaware basin because “the economics are still there.”
The Permian and Granite Wash each edged down a unit this week to respective totals of 164 and 9. The Permian has now shed 504 units since a recent peak on Dec. 5, 2014. The Barnett edged up a unit to 4.
New Mexico fell 3 units to 18, down 85 from its peak on Dec. 19, 2014, and its lowest level since the 1990s.
Alaska and California each dropped 2 units to 11 and 6, respectively. Pennsylvania, Ohio, Wyoming, and Utah each edged down a unit to respective totals of 16, 12, 9, and 0. The Utica also edged down a unit to 12.
Pennsylvania’s count, down 100 units since its peak on Jan. 20, 2012, is at its lowest point since Sept. 28, 2007.
Two states reported increases this week. West Virginia edged up a unit to 13. Due to the 2 offshore rigs coming online, Louisiana’s count gained 2 units overall to 47. The Haynesville edged down a unit to 14.
The Cana Woodford posted the largest gain of the basins, collecting 3 more units to reach a total of 36, while the Arkoma Woodford edged down a unit to 4.
Better completions, fewer rigs
In addition to Sheffield, Dave Hager, chief executive officer of Devon Energy Corp., gave insight into how his firm has staved off the worst operational effects of the downturn. Both boasted their firms’ lower rig counts and improved completions, which Hager said makes rig counts “kind of an obsolete measure.”
Devon is now using about 1,500 lb/lateral ft of sand and has used up to 3,000 lb/lateral ft, he said. As a result, Devon has improved 30-90-day initial production rates from large plays by 75-100%.
PNR is also adding more sand, Sheffield said. “We’re reducing cluster spacing from 60 ft to 30 ft to 15 ft to 10 ft. We’re taking laterals in the Permian basin where we started at 5,000 ft—we’re all the way up to 12,500 ft now.”
PNR is among several E&P firms to have already reported rig reduction during the course of 2016 (OGJ Online, Feb. 19, 2016).
WPX Energy Inc. said this week that it plans to deploy up to 3 rigs in the Delaware this year. Current activity is concentrated in the Wolfcamp and Bone Spring plays.
The firm says it continues to implement enhanced drilling and completion designs in the Delaware, including longer lateral lengths of 1.5 miles, more sand per stage totaling 1,500-2,000 lb/ft, and tighter perforation cluster spacing. The company also is evaluating the potential to drill up to six 2-mile laterals in 2016.
WPX plans to run 1 rig in the Williston, where it intends to defer completions after completing a 6-well pad in March. The firm also plans to deploy 1 rig in the San Juan basin this year.
Concho Resources Inc. currently has 8 horizontal rigs in the Delaware, with 6 in the northern portion and 2 in the southern portion. The company currently has 1 horizontal unit in each of the Midland basin and New Mexico shelf.
SM Energy Co. currently has 4 operated rigs, including 2 in Divide County, ND; 1 in the Eagle Ford East area; and 1 in the Permian, where it expects to redeploy a second rig from the Eagle Ford this year.
The firm’s 2016 drilling program targets the Wolfcamp B and Lower Spraberry intervals. In January, SM Energy reinitiated drilling activity on its Sweetie Peck asset, which it describes as a prime position in Upton and Midland Counties, Tex., and includes 15,200 net contiguous acres.
SM Energy has DUC inventories of 76 from the Eagle Ford and 40 net operated wells from the Bakken-Three Forks.
QEP Resources Inc. anticipates that its working rig count will decline from 9 at yearend 2015 to 3-4, with 1 each in the Williston and Permian basins and Pinedale, by the beginning of second-quarter 2016.
Other firms shedding rigs
Chesapeake Energy Corp. plans a companywide average operated rig count of 4-7 in 2016 and to complete 280–350 wells.
In the Haynesville, where the firm averaged 6 units in fourth-quarter 2015, it intends to use up to 3 units during the year and plans to place 50-60 wells on production. In its STACK position, the firm plans to use up to 3 rigs and place 35-45 wells on production.
Chesapeake has released both of its units that operated in the Utica during the fourth quarter. It expects to place 45-55 wells on production in the play during 2016. The company also released its 1 working unit in the Marcellus during the fourth quarter, and plans to place 20 wells on production this year.
All operated rigs have been released from the Powder River basin, where the firm plans to place 5 wells on production in 2016. Chesapeake’s averaged 3 rigs working in the Eagle Ford during the fourth quarter, and the company anticipates releasing all operated rigs in the area by June. It plans to place 170-180 wells on production from the play this year.
Whiting Petroleum Corp. plans to run 2 units in each of the Bakken-Three Forks and Niobrara for the balance of the year. At yearend 2016, the company projects an inventory of 73 DUC wells in the Bakken-Three Forks and 95 in the Niobrara.
The company noted that it has continued to test larger sand volume completions across its acreage in the Williston. In the fourth quarter, Whiting completed 21 operated wells that produced for 30 or more days and had average sand volumes of 6.7 million lb.
Wells completed during the fourth quarter reached an average 30-day rate of 1,339 boe/d, which was 22% better than the third-quarter wells.
Newfield Exploration Co. plans to run 4–6 operated rigs in the Anadarko basin and expects to drill 80 wells in 2016. It will run an active rig program in its STACK area to hold acreage by production.
Stone Energy Corp. said its contracted rig for its Appalachia acreage was available for delivery late in fourth-quarter 2015, but remains stacked.
Contact Matt Zborowski at firstname.lastname@example.org.