It’s reset time in the oil services sector as an uncertain 2013 gets under way. Domestic rig count did its own reprise of a fiscal cliff tumble as the fourth quarter 2012 spiraled to an end, dropping 41 units in the final week of December and exacerbating a trend that saw fourth-quarter 2012 average rig count finish 4.5% below third-quarter levels.
While late fourth-quarter seasonal drops in rig count are the long-term norm in the industry, thanks to a combination of weather, year-end budget expiry and smaller privately held operators finishing out drilling programs, something about the end of 2012 seemed, well, different. Part of it was due to the velocity gain in the activity drop. Average quarterly rig count had deflated at a rate between 40 and 50 units per quarter after peaking in the fourth quarter of 2011. But that rate accelerated to 66 units in the fourth quarter of 2012, when the average number of rigs listed as drilling ahead dropped to 1,374 ? the lowest number since third-quarter 2010.
Similarly, after two years of impressive gains following the dim days of 2009, average annual domestic rig count fell 60 units, or 4%, to 1,462 in 2012, roughly midway between the peak of 1,877 recorded in 2008 and the trough of 950 one year later in 2009.
Thus the fourth quarter 2012 exited on a down note, bringing an end to a year that began with hopes of a 7 to 10% increase in domestic drilling activity. With domestic capital spending expected to be flat in 2013, it appears that annual rig count will also finish down incrementally when the final numbers are in one year from now — though quarterly rig count in 2013 should be higher than that recorded in fourth-quarter 2012.
So what changed? A look at three key trends in 2012 suggests the industry is undergoing a transition that will continue into 2013. Those key themes include:
Commodity Prices: The year 2012 began with soaring crude oil prices and rapidly deflating natural gas prices on the basis of a historically warm winter. Wellhead prices for crude oil hit $100 in November 2011 and remained above $95 for seven straight months. Conversely, natural gas prices spent 11 months below $3 in 2012 and ultimately fell to 10-year lows, dropping to $1.89 at the well head in April 2012. At midyear, natural gas liquids prices also collapsed while crude oil experienced a temporary setback, with wellhead prices falling from a peak of $105.42 on average in March 2012 to $83.59 in June 2012.
This combination of events in the commodity markets in 2012 slowed capital flow to operators, many of whom were involved in outspending cash flow to develop unconventional plays or who were involved in an expensive corporate strategic shift from dry gas to oil and liquids. Monthly revenue from domestic oil and gas production, which averaged $27.6 billion during the first quarter of 2012, fell to $24 billion in the second quarter, and recovered to $25.9 billion at the end of the third quarter. The impact on oil services was predictable. Less money coming in ultimately manifests as less money going out for oil services. After peaking at 447 rigs targeting dry gas objectives in fourth-quarter 2010, dry gas rig count fell to 182 on average for fourth-quarter 2012, with most of that drop occurring after the first quarter of 2012. Overall, average quarterly rig count for dry gas drilling fell 40% in 2012 from 305 to 182.
Despite the drop in drilling activity, gas production remains resilient at nearly 65 Bcf/d heading into 2013. And despite expectations that domestic gas production will roll over later this year because of a lower gas-directed rig count, it is unlikely to do so at a level that will have a material impact on the overall supply/demand imbalance.
Current efforts to develop tight oil are also producing significant volumes of natural gas and natural gas liquids, some of which remain stranded pending the completion of infrastructure to get the product to market. Thus, expectations for a recovery in gas-directed drilling during 2013 are premature with dry-gas rig count unlikely to improve until late in the year, if at all. The positive news is that dry gas rig count appears to have bottomed.
While there was some recovery in natural gas and crude oil prices as 2012 came to a close, NGLs remained under pressure, partly as a result of bottlenecks in transportation and processing capabilities. For 2013, it looks like more of the same with oil prices expected to remain flat.
Too Much Capacity: The drop in drilling activity in dry gas plays prompted contractors to relocate oil services equipment into oilier basins. As an example, combined rig count in the Barnett and Haynesville shales averaged 88 units in the first quarter of 2012, but just 44 units in fourth-quarter 2012. Conversely, the only unconventional or tight formation plays to record an increase in rig count during the course of the year included oily plays such as the Mississippi Lime, the Bakken shale and strong liquids plays such as the Utica shale.
The drop in drilling activity in dry-gas plays coincided with the arrival of newbuild equipment as contractors took delivery for both pressure pumping spreads and new drilling rigs ordered during the 2010-2011 era, when high demand in oil and natural gas basins created a short supply situation across service lines.
Contractors reined in mobilization efforts in 2012. The number of newbuild rig orders, which peaked at 70 units in the second quarter 2011, fell to less than a dozen per quarter on average in 2012. The drop in orders signified that all those newbuilds ordered in 2011 represented a one-off trend among operators to move from delineation and optimization efforts into resource harvest mode in 2012. It now appears that the pieces have been set on the industry game board and that enough equipment is at hand to meet 2013 demand — hence the decline in new rig orders and the continuing effort to stack out lower-spec surplus equipment.
Assigning a number for well stimulation capacity quarterly remains an art rather than a science, but it appears that domestic demand for well stimulation, as measured by hydraulic horsepower (HHP), peaked at roughly 10.6 million HHP in the fourth quarter of 2011, but finished 2012 at roughly 9.1 million HHP, leading to utilization of less than 80% for the industry, which was accompanied by a corresponding drop in well-stimulation prices.
The oversupply situation will continue in 2013 and remain acute until natural gas prices recover. High demand in both oil and gas plays creates a tight oil services industry. But the industry has too much equipment when one sector, like natural gas, is weak. While demand remains steady for high-end equipment classes as operators upgrade programs, the domestic market will be characterized by too many rigs and too much hydraulic horsepower in 2013, though the oil services market is expected to improve as 2013 rolls into 2014.
Falling Service Costs for Operators: Rig rates peaked in early 2012 and began dropping, particularly for older electric rigs and legacy conventional mechanical units. Rig rates flattened for high tech joystick rigs by mid-2012 and began to soften incrementally at year-end as rigs exiting contracts in dry gas basins began competing with arriving newbuild equipment in active oily markets.
Meanwhile, pressure pumping costs fell in 2012 when measured on a per stage basis. Because of basinal diversity, well stimulation is a tough industry to monitor in regard to averages, but a rough estimate shows the average price per stage nationally dropping from roughly $150,000 in early 2012 to slightly more than $100,000 as 2013 gets under way.
A price spike in well consumables such as guar on the basis of a short harvest in India characterized mid-2012, but the industry now appears to have adequate supplies of proppants and additives on hand in the supply chain, further decreasing any oil services inflationary pressures in 2013. The story in 2012 switched from margin expansion to margin degradation. It appears the 2013 story will be all about margin stabilization and, if all goes well, recovery later in the year.
Rising Efficiency: Fewer days to drill wells coupled with improvements in completion practices as operators evolved from optimization to resource harvest across multiple shale plays indicate the industry is getting better at what it does and suggests a need for less equipment to meet program targets. That news surfaced in a big way during third-quarter earnings calls as several operators provided commentary that they were able to meet drilling program targets in terms of well numbers with fewer rigs. That resulted in several operators releasing rigs in the Eagle Ford, Marcellus and Bakken shales. In all, it appears that the more savvy oil and gas companies can get by with as many as 10% fewer rigs than had been the case previously, thanks to an emphasis on pad drilling and improvements in well drilling and completion cycle time.
When efficiency gains were pared with 2012 capital spending, which was front-end loaded during the first half of the year to capture the benefits of high crude oil prices, the combination resulted in a measurable decline in oil services activity in the fourth quarter.
Large efficiency gains occur early in the shale cycle; afterward, efficiency gains become incremental. With no new major shale plays on the horizon outside the Permian Basin Wolfcamp, 2013 is likely to see further diffusion of efficiency gains in newer plays like the Eagle Ford, but lesser gains elsewhere. That argues that flat spending in 2013 actually implies incrementally lower rig count overall.
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Advanced geophysical techniques can be used to discern crucial reservoir properties in unconventional reservoirs.
An objective view is needed to determine best processes, Ely says.