A week after beginning the year with its largest decline in months, the US drilling rig count dropped 14 units to 650 during the week ended Jan. 15, according to data from Baker Hughes Inc.
The total remains the lowest since Aug. 20, 1999, and down 1,026 year-over-year.
With losses in 19 of the last 21 weeks and the absence of an increase since Aug. 14, 2015, an end to the downward spiral appears distant, an inclination validated by Raymond James & Associates indicated last week.
The financial services firm projected the overall US count to lose an additional 150 units during the first half of this year, bottoming out at 550 in June before a modest recovery in the second half (OGJ Online, Jan. 8, 2016).
More gas rigs going offline
Unlike in most weeks during the protracted industry downturn, natural gas-directed rigs represented a bulk of the declines, decreasing 13 units to 135, down 175 year-over-year. Last week, gas-directed rigs posted a 14-unit drop as part of the overall US count's 34-unit dive.
Oil-directed rigs, down 20 last week, edged down 1 unit this week to 515, down 851 year-over-year and their new lowest total since Apr. 30, 2010.
Land rigs fell 12 units to 623, down 987 year-over-year. Rigs engaged in horizontal drilling dropped 8 units to 511, down 742 year-over-year and their lowest level since Nov. 6, 2009. Directional drilling rigs lost 2 units to 62.
BHP Billiton Ltd. said this week that it plans to reduce its operated rigs onshore US from 7 to 5 in the first quarter following a pretax writedown of $7.2 billion on its US onshore assets (OGJ Online, Jan. 15, 2016). The company operated 26 rigs onshore US only a year ago.
In July 2015, BHP wrote down $2.8 billion pretax in US onshore assets, primarily in the gas-focused Hawkville field of the Eagle Ford.
One rig went offline offshore Louisiana, bringing the overall US offshore total to 26, down 28 year-over-year. One rig drilling in inland waters went offline, cutting the total to 1.
Adding 83 units to double its count last week, Canada continued its upward momentum with a 61-unit jump to 227, still down 213 year-over-year.
Oil-directed rigs gained 39 units to 110, down 124 year-over-year. Just 12 oil-directed rigs were operating in Canada 2 weeks ago. Gas-directed rigs rose 22 units to 117, down 89 year-over-year.
Most losses in Texas, Louisiana
Texas led the major oil- and gas-producing states with a 7-unit decline to 301, down 465 year-over-year and its lowest count since Apr. 5, 2002.
The Permian also dropped 7 units, settling at 202, down 285 year-over-year. The Eagle Ford lost 3 units to 68, down 117 year-over-year. The Barnett lost 1 unit to 5. The Granite Wash, meanwhile, increased 2 units to 14.
Following its rig count reduction, BHP during the first quarter plans to operate 3 units in the Eagle Ford’s Black Hawk field and 2 in the Permian.
Louisiana fell 5 units to 54, down 53 year-over-year and its new lowest total since BHI began tracking states’ rig counts in January 2000.
North Dakota, New Mexico, and Colorado each lost 2 units to 47, 32, and 20, respectively. North Dakota, down 109 year-over-year, is at its lowest level since Oct. 2, 2009; New Mexico, down 60 year-over-year, it at its lowest level since May 15, 2009; and Colorado, down 44 year-over-year, is at its lowest level since Nov. 10, 2000.
The Niobrara decreased 3 units to 19, down 35 year-over-year, while the Williston dropped 2 units to 47, down 118 year-over-year.
Wyoming and Ohio each edged down a unit to respective totals of 15 and 13. The Utica edged down a unit to 13.
Unchanged from a week ago were West Virginia at 12, Alaska at 9, and Utah at 3
Pennsylvania, Kansas, and California each edged up a unit to 26, 12, and 8, respectively. The Marcellus also edged up a unit, reaching 38.
Oklahoma led all with a 4-unit jump to 87. The Cana Woodford and Mississippian each gained a unit to respective totals of 37 and 12.
Projected US oil output declines, rebound
In its Short-Term Energy Outlook released this week, the US Energy Information Administration forecasts US crude oil production to decline from 9.4 million b/d in 2015 to 8.7 million b/d in 2016 and 8.5 million b/d in 2017 (OGJ Online, Jan. 13, 2016).
The declines reflect an extended drop in Lower 48 onshore production partially offset by growing production in the Gulf of Mexico, where new projects are seen boosting output from 1.6 million b/d in 2015 to 1.9 million b/d in fourth-quarter 2017.
EIA sees US overall crude production declining steadily from 9.2 million b/d in December 2015 to 8.5 million b/d in November 2016. By second-half 2017, more than 2 years of falling Lower 48 onshore output is expected to end as a result of productivity improvements, lower breakeven costs, and anticipated oil-price increases.
Onshore production averaged 7.6 million b/d in second-quarter 2015, and is projected to fall below 6.2 million b/d in September 2017 before increasing modestly in fourth-quarter 2017.
In the near-term, EIA expects February crude output from seven major US shale plays to fall 116,000 b/d to 4.83 million b/d, according to the agency’s latest Drilling Productivity Report (DPR) (OGJ Online, Jan. 11, 2016).
Production from the Eagle Ford is seen dropping 72,000 b/d during the month to 1.15 million b/d, which is followed by a 24,000-b/d loss in the Bakken to 1.1 million b/d and 23,000-b/d loss in the Niobrara to 371,000 b/d. Continuing to demonstrate its resiliency, the Permian is forecast to increase 5,000 b/d to 2.04 million b/d.
New-well oil production/rig across the seven plays in February is expected to increase by a rig-weighted average of 3 b/d to 497 b/d. The Niobrara is again seen leading the way, expected to post a 16-b/d jump to 726 b/d, while the Utica is seen rising 12 b/d to 294 b/d and Eagle Ford rising 9 b/d to 804 b/d.
“Despite the significant decline in total rig counts in 2015, rig counts have largely stabilized in the core counties of the Bakken, Eagle Ford, Niobrara, and Permian,” EIA notes in the STEO, adding that in the next couple of years, “falling costs and ongoing technological and process improvements in rig, labor, and well productivity are anticipated to lead to faster rates of well completions and less-rapid production declines relative to other Lower 48 onshore areas.”
Contact Matt Zborowski at [email protected].
