Ask not for whom the bell tolls, service providers.

After all, it’s hard to shake a feeling of impending doom these days as sell side oil service analysts deliver a steady eulogy of downgrades to land drillers and pressure pumpers with onshore ties to North America.

The funereal dirge grew more somber in the last week as further evidence of falling rig rates, a slow Canadian summer (as presaged at Hart’s DUG Canada Conference in Calgary in June), and self-reported pre-announcements across all land-related service sectors reached critical mass.

The takeaway is that the third quarter was time spent in assisted living for most service providers, regardless of sector, with sell side analysts now relegating fourth quarter performance to the financial equivalent of hospice on the basis of falling revenues, declining utilization, shrinking EBITDA, and 2013 margin compression. Consequently analysts are scrambling to downgrade ratings for the oil services sector in general, which is often reflected in a whopping drop in ratings for individual companies from “accumulate” to merely “buy”.

Oh, the horror of it all.

A peak behind the angst on Wall Street illustrates five major themes impacting rig count as 2012 rounds third base and charges for home. All are interrelated and point to further activity declines, further reductions in service pricing and falling utilization through yearend. It is not clear whether any of the five themes are enough to prevent recovery after the first of the year. After all, WTI remains stubbornly above $90 and, with crude oil revenue now accounting for the overwhelming majority of revenue flow into the industry, operators will have money to spend in 2013, more money, in fact, than is on hand currently.

First off, where is rig count declining? The door prize goes to unconventional dry gas. Examples of year-over-year declines in average quarterly rig count for the third quarter 2012 compared to the third quarter 2011 find the core Louisiana Haynesville down 80%, the Arkoma Woodford down 54%, and Colorado’s Piceance Basin off 50%. Similarly, the Barnett shale and Greater Green River Basin are off more than 40% while the Fayetteville and Marcellus shales are down 30% and 29% respectively.

In liquids plays, the Cana Woodford is currently off 40% versus the same quarter in 2011 while the Granite Wash is down 23%. In contrast, Eagle Ford shale rig count is up 1% and the Utica shale is up 384% versus the same quarter in 2011. All the tight oil basins are up, including the Cleveland/Tonkawa in the Texas Panhandle, which is up 8% versus the same quarter in 2011, and the Bakken shale, which is up 25%. The Mississippi Lime is up 384%.

Table shows changes in quarterly average rig count for select unconventional oil and gas plays. Dry gas basins have experienced the greatest decline while tight oil formation basins are experiencing rig count growth. The change versus the third quarter 2011 and the 2nd quarter 2012 gives some insight into whether the change is accelerating or decelerating. For example, the Marcellus shale is down 29% versus the third quarter 2011 and down 20% versus the second quarter 2012. So most of the decline in rig count is a recent phenomenon.

No Rig is an Island

As goes the land drillers, so go the rest of the service industry. No sector, to paraphrase the English poet John Donne, is an island entire of itself. So, what’s up with the decline in domestic rig count? In no particular order, here are five reasons underlying falling rig count.

Greater Rig Efficiency—Operators in the Eagle Ford and Marcellus shales, and the Cana Woodford touted efficiency gains during second quarter 2012 earnings calls. Those gains came as operators made significant progress in optimizing drilling and completion efforts as new plays matured, significantly reducing cycle time. In newer plays, like the Eagle Ford and Marcellus, those gains were sizeable, sometimes reaching a 50% reduction in drilling cycle versus earlier wells in the play.

But gains in drilling cycle show the same profile as decline rates for unconventional wells. Massive gains are made quickly before tapering into a long tail of modestly incremental improvement. It is part of the unconventional cycle. As plays mature, operators capture gains in drilling time and the emphasis on improvement subsequently shifts to the completion cycle, particularly as a play nears the resource harvest phase. The Bakken is there. The Eagle Ford and Marcellus are quickly getting there. What it means is that operators are drilling wells faster.

No More Money—The consequence of drilling faster influences the second theme in declining rig count. Operators have burned through 2012 budgets.

“Lower commodity prices are one factor in declining rig count,” said Larry Pinkston, CEO at Unit Corp. (NYSE: UNT). Pinkston, who spoke at the IPAA OGIS meeting in San Francisco at the end of September, addressed reduced rig count in the Anadarko Basin, though his observations are relevant for the drilling market as a whole. “But the major reason (for declining rig count) is that operators have spent their budget… Liquids prices, sure, that had something to do with it, but if people still had money in their budget, they’d still be drilling.”

Market Evolution—This is most apparent in the Permian Basin as operators allocate capital expenditure to horizontal programs to explore new plays such as the Wolfcamp horizontal, or the Cline shale. Rigs formally focused on drilling Wolfberry targets, which is a stacked vertical commingled production play, have been let go. In some cases those rigs moved to areas in the southern Midland Basin where the Wolfcamp is shallower and where smaller spec rigs can drill horizontal laterals. Still, several rigs have not found work. Vertical oil-rig count in the Permian Basin, which is primarily Wolfberry-oriented, peaked early in the second quarter 2012 at more than 280 units, according to Smith International’s rig count. That count had dropped to 240 at the end of the third quarter 2012 while horizontal rig count in the Midland Basin portion of the Permian Basin increased during the same period.

Oil and gas operators are filling cubicles with petrophysicists, geophysicists —and other specialists—to review tight oil formations in the Permian. The process enables operators to identify sweet spots that make tight formation wells economic even at $8 to $10 million per pop.

“With our mandate to drill close to within cash flow, we have to allocate capital, and we have great returns from the horizontal Bone Spring so, yes, we are taking vertical rigs out and shutting them down in the Yeso and Wolfberry or sending them to higher rates of return in the Bone Spring,” noted Steve Pruett, senior vice president of corporate development at Concho Resources Inc. (NYSE: CXO) at the IPAA OGIS San Francisco conference.

Commodity Prices—Although natural gas rallied in September when it became evident the U.S. would not fill underground storage, prices are still too low to bring about a revival in the natural gas market. Same story for NGLs. Pricing has recovered since early summer, but is well below previous levels as takeaway issues create a flood of NGLs in the market. Consequently, operators in liquids rich plays, which drove much of the increase in 2011 rig count, are slowing activity. Natural gas drilling likely doesn’t recover until the market tops $4.50 on a sustainable basis. Black oil, the new term for crude oil, remains the prime driver in activity gains. With WTI above $90, operators will start 2013 with more cash on hand and that circumstance usually coincides with higher demand for oil services.

2013 Capex Plans In Flux—In plays like the Cana Woodford, which are dominated by a handful of operators, 2013 budgets are still evolving. Of the Four main players, Devon Energy Corp. (NYSE: DVN), Marathon Oil Corp. (NYSE: MRO), QEP Resources Inc. (NYSE: QEP), and Cimarex Energy Inc. (NYSE: XEC), all participate to some extent in each other’s wells.

“All of us are finding our non-operated obligations are increasing because of these infill drilling projects,” notes Tom Jorden, CEO for Cimarex. Jorden, speaking at the IPAA OGIS meeting in San Francisco, outlined the situation in regards to falling rig count in the Cana Woodford for analysts. “Everybody is trading plans for next year so we can all run on our capital. So a lot of what we do in Cana next year is going to be a function of how much outside operated capital we are exposed to.”

Cimarex will exit 2012 with four rigs active in the Cana, down from 12 at the beginning of the year. The company has yet to determine the number of rigs it will employ in 2013. “If we are in a non-operated well, we’re going to participate in that. So we’re going to see what our non-operated obligations are, and then the swing capital for Cana will be our operated capital.”

Overall rig count in the Cana Woodford is down nearly two-dozen units from its 2011 peak.

For Whom the Bell Tolls

Bottom line? Gas bad; oil good while the status of NGLs is in flux. With declining rig count, the land drilling sector has become an analog for the greater services market: demand is down, more capacity is arriving in an oversupplied market, spot market pricing is dropping, while units that roll off contract are seeing contract renewals for shorter terms. Those themes are rippling through the oil services and creating angst among sell-side analysts in regards to fourth quarter 2012 performance with little visibility into 2013.

So ask not for whom the analyst bell tolls, service providers. The bell tolls for thee.

Contact the author, Richard Mason at: rmason@hartenergy.com

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