Falling Like Dominoes

?The first half of 2008 was a dream come true for the oilfield-service sector, with many companies reporting their best quarterly earnings ever. New-build rigs were joining the drilling party and still more were on order, as the U.S. count marched toward 2,000. Backlogs grew to all-time highs for rigs, gas compressors, remotely operated vehicles for subsea work, and most other equipment on land or sea.

But since then, the service sector has found itself in a fitful nightmare from which some experts think it may not wake until 2010. The rig count at press time was down to 1,170, affecting not only drilling firms, but also those that provide water hauling, pressure pumping, drilling mud, logging and most other services.

Analysts at Tudor, Pickering, Holt & Co. Securities expect activity in 2010 to be flat with 2009 and any meaningful oil and gas demand recovery to be pushed to 2011. This does not bode well for the service sector.

Executives, investors and analysts alike have been surprised by the depth and speed of the activity slowdown, which has been spreading through­­out the U.S. oil patch, and, lately, abroad.

“This cycle has been more vicious than previous cycles, with minimal visibility moving forward,” analysts with Pritchard Capital Partners report. “The 42% rig count decline in 2008-09 is outpacing (declines) of the mid-1980s and the 2001–02 and 1997-98 cycles, which were down 36%, 32% and 7%, respectively, over the first 25 weeks from each cycle’s peak.”

The reasons are clear. Many wells are now uneconomic to drill or produce. At press time, gas was about $4 per million Btu on the Nymex. A recent report from Credit Suisse illustrates the challenge service-company customers face: The Wattenberg play in Colorado’s Denver-Julesburg Basin needs a $6.40 gas price to generate a modest 10% internal rate of return—which these days, would just about match the cost of capital for some E&Ps.

Rig count woes

Operators have responded quickly by cutting their 2009 budgets and redeploying precious capital only to the highest-margin regions. For example, St. Mary Land & Exploration is cutting its rig count from a high of 16 last year to about six for the rest of this year. XTO Energy Inc. has only two rigs working in the Permian and San Juan basins, versus 11 in third-quarter 2008. Swift Energy Co. cut its drilling budget 80%.

The first domino to fall was the rig count for marginally economic, vertical wells operated by private and small-cap E&Ps. Most vulnerable here are smaller-cap drilling contractors that have older fleets and drill shallow wells. Union Drilling Inc., for example, incurred a loss of 12 cents per share in the fourth quarter due to bad debt expense after four of its customers went into bankruptcy.

Rig productivity models show that as the rig count falls, onshore gas production may dip by fourth-quarter 2009 and through 2010. An inventory of drilled, but uncompleted, gas wells is also building.

Everyone on the E&P side of the table thinks that either gas production has to fall to revive prices, or drilling and well-service costs have to fall further than the 15% they already have. How low can service costs go?

Until that question is answered, more E&P companies are reducing their 2009 drilling budgets, some for the second and third times since December. Now, reports are of delay or cancellation of deeper wells in better plays, operated by larger companies.

By the end of February, the rig decline had reached into a premier shale. RigData reports that 227 rigs were operating in the Barnett on October 3. By February 27, 110 were in the field. “That represents a 51.5% drop in the number of drilling rigs in the Barnett in 22 weeks,” says Gene Powell, editor of the Powell Barnett Shale Newsletter.?

Through early March, the U.S. vertical rig count was down 46%, and the directional rig count had retracted 41%. The horizontal rig count—that is, drilling shales—was off the least, by about 30%, according to Baker Hughes Inc. and other companies that track rig activity.

West Texas, the Midcontinent and the Rockies have been particularly hard hit, with the count in Colorado’s Piceance Basin decimated, down 64% since last fall. The Texas count in early March was down by 404 rigs from March 2008. Drilling in the Williston, Woodford and Fayetteville plays has fallen 29%, 28% and 12%, respectively, while the Haynesville and Marcellus have remained relatively strong. Too, operators are delaying the fracturing of their wells, or are waiting to tie them into sales pipe.

The unattractive economics of gas drilling to an industry leader such as EOG Resources Inc., which has cut its plans, should be a warning to the rest of the industry, says Bernstein Research senior analyst Ben P. Dell. “The fact that the company with the industry’s lowest (finding) costs will not increase production in 2009 means that other gas-producing companies will be forced to cut growth as well,” he says.

For service companies, this means a lower gas-rig count for some time to come. That challenges the bottom line of not just drillers but also pressure-pumping companies that perform frac jobs and other companies that work on complex wells.

Forecasts

Rig-count and earnings forecasts are being revised downward for the rest of 2009 and, lately, on into 2010, as the realities of hydrocarbon demand and lower commodity prices continue to sink in.

“Concerns are mounting that we will see a repeat of the mid-1980s, when excess capacity led to at least a decade until the industry began to recover,” the Pritchard analysts report. “But we see differences between then and now, mainly the better-capitalized contractor balance sheets and highly differentiated rigs. Still, (rig) companies on conference calls are more often pointing out that this recessionary oilfield environment could last into 2010, rather than looking for a rebound in 2009.”

The vertical rig count has declined the most, but rigs drilling horizontally were starting to be set aside more often in the first quarter. Since last fall, the overall U.S. count is down 45%, according to Baker Hughes Inc., with even greater declines in West and South Texas and the Rockies.

Robert Mackenzie and Rehan Rashid, analysts for FBR Capital Markets, a unit of Friedman, Billings, Ramsey & Co., have revised their 2009 land-rig forecast to 882 from 1,180, representing a 55% year-over-year decrease. “We are also introducing our 2010 forecast, which calls for another 11% decrease to 782. After the gas markets balance in 2010, we expect the rig count to increase to 1,220 long term, the level needed to maintain production with shale gas.”

The surplus of gas, blamed primarily on surging shale production, will abate as the rig count falls. This represents the biggest factor in the onshore service-company outlook.

The gas-rig count is falling faster than people expected due to weak prices of $2 to $3 in many plays, after one deducts the basis differential from Nymex prices, and the cost of gas compression and transportation. Most observers expect the gas-directed rig count to fall to 700 or 750. It has already fallen from 1,606 at the peak last year to 933 rigs as of March 6.

“Due to the normal lags associated with the backlog of completions and tie-ins, our rig productivity models show that onshore supply will begin to dip by the fourth quarter, exiting the year down about 2.4 billion cubic feet a day on a year-to-year basis,” says Credit Suisse analyst Jonathan Wolff.

“On recent calls, companies are ambivalent about plans to scrap rigs. At the same time, firms have stopped ordering new high-efficiency rigs and, in some cases, are deferring or canceling previous orders…Things look more and more like they’ll get worse before they’ll get better.”

FBR’s Mackenzie will become more optimistic “once a spot land-drilling market shows signs of developing. We think there is limited downside left to investors’ North American expectations, but international sentiment could still soften.” Yet, he adds, “The U.S. land-drilling outlook is awful.”

Nabors Industries Inc. is the bellwether for land drilling and well servicing, with a fleet of 528 land rigs and 763 land workover rigs. “We believe land-drilling spot-market cash margins could approach early-2000 levels of around $2,500 per day. With roughly a third of Nabors’ fleet contracted in 2010, however, presumably at cash margins of roughly $10,000 a day, we are modeling an average $6,000-a-day cash margin,” Mackenzie says.

“Roughly a third of the land-rig fleet has been built over the last several years, which should create an oversupplied market as long as the rig count remains around 1,000.”

Costs falling

Given these events, it would seem natural that costs for energy projects would fall. But Candida Scott, senior director, cost and technology, at research and consulting firm CERA, sees some caution.

“While there is some adjustment in costs, we do not expect to see a drop in (well-construction) costs equivalent to the recent drops in oil and steel prices. Investors are reviewing spending decisions and trying to determine how much costs will fall before approving new projects,” she says.

“Despite the need to reduce expenses, companies do not want to cut personnel. They realize the bind they got into when they laid off so many skilled workers during previous downturns and they want to avoid making the same mistakes.”

If costs for services and supplies do not fall, look for more acquisitions, assuming buyers and sellers can agree on valuations. Andy Byrne, vice president and senior equity analyst for IHS Herold, says, “Adding reserves through acquisitions is likely the way to go for some companies. 2009 is shaping up to be a better year to drill for oil on Wall Street than it is to explore for oil and drill it themselves.

“With commodity prices so low, it is cheaper for companies to buy reserves than to rent a drilling rig and find and extract the oil.”