The oil and gas industry was in the grips of frac fever in 2011. Nearly 16,000 horizontal wells were drilled (a record), each requiring more powerful and complicated stimulation than wells completed even just a few years ago. The need to hold acreage with production and the industry's transition to oil and liquids drilling compounded problems caused by physical equipment shortages. Hundreds of millions of dollars were thrown into the domestic market to chase robust margins.

But the market has had time to adapt, and the frac-service environment may be shifting. Oil and Gas Investor surveyed the frac business landscape to determine what E&Ps can expect this year from one of the hottest markets in recent memory.

Horizontal drilling is the chief driver of frac demand, says Richard Spears, vice president of Spears & Associates Inc., a Tulsa-based consultancy that specializes in market research and activity forecasts for the energy industry.

According to Spears, the number of horizontal wells drilled increased more than 200% from 2009 to 2011, to roughly 16,000 horizontal wells from 6,800 two years prior. This drove fierce demand for fracing, which the service industry scrambled to meet. Spears sees continued growth in horizontal drilling in 2012 and estimates more than 18,000 horizontal wells will be drilled this year. That would represent nearly 275% growth from 2009 levels, but only 15% over 2011 numbers.

Frac horsepower has increased significantly since 2003 from both the three major service companies and dozens of other smaller players.

A combination of persistently low natural gas prices and the influx of new frac fleets into the marketplace may already be driving down service prices, according to some analysts. Though drilling activity is expected to grow, some of the slower gas basins are already seeing price concessions, says John Daniel, director and cohead of oil service research at Simmons & Co. International Inc. Daniel says that equipment in the field will catch up with demand this year, but in the meantime, frac fleet operators are redeploying equipment into areas where demand is still strong. Those margins mean quick recovery of investment for equipment, even now.

"We have heard of pricing concessions in the Haynesville, Barnett, Fayetteville and the Marcellus," Daniel says, which is not unexpected with weak gas prices. Anecdotal evidence shows similar pricing shifts in the Eagle Ford, leading to some debate about fundamental conditions there. Daniel says pricing concessions suggest overcapacity in those markets. The Permian and Bakken frac markets remain tight.

The separation is driven by margins, which in many cases are still exceedingly good—good enough to return the initial $40-million investment on a brand new, 40,000-horsepower spread in a matter of months. This return depends on number of stages and frac days per month, but Daniel outlines a scenario where economics still support deploying new fleets into the market, as some companies are doing.

Returns depend on the basin. A pumper in the Marcellus may see revenue near $120,000 per stage, whereas the Permian may bring $50,000 to $70,000 per stage. If the fleet works 20 days per month and completes four to five stages per day, the implied revenue would exceed $100 million annually. At current EBITDA margins, the frac fleet cost would be repaid in roughly a year.

"As long as people can make that type of math work, entities will likely continue to enter the space," says Daniel.

"I count roughly 45 guys that either play in the North American frac market or are preparing to go into it," he says. Despite pricing pressures, there are still basins where pressure pumpers can make good returns, and equipment has yet to find equilibrium.

Daniel says another 4 million horsepower is on order, a bit lower than the amount of new horsepower delivered into the market in 2011, which was close to 4.5 million. New capacity is headed for the stronger domestic oil basins, with a small portion headed to international destinations.

On the company's most recent earnings call, management of industry leader Halliburton announced that this year the company would redeploy some frac capacity out of gas areas into liquids-rich arenas, and increase the percentage of new capacity additions sent internationally.

Halliburton performed the first shale fracs in several countries last year, including Argentina, Mexico and Saudi Arabia, and it expects international demand for frac services to expand, if pricing and regulation are favorable.

Spears & Associates' research indicates North America is 88% of the frac market. This accounts for an estimated $27-billion opportunity. The research concludes there will be 18 million horsepower in North America in 2012.

Most continents have significant volumes of hydrocarbons locked in shales, and countries with aggressive development plans—such as Poland, where Halliburton in 2011 performed the country's first shale frac—may be growth areas sooner rather than later.

Shifting crews

Halliburton president and chief executive David Lesar said capacity additions to North America will be flat.

"We do not expect to be increasing pressure-pumping capacity beyond 2011 levels," he said, though the past quarter produced the highest revenue in Halliburton's history. Oil and liquids-related revenue accounted for 70% of the company's upstream revenue, up from 50% five years ago. Lesar also said that average well footage has risen to 7,000 feet from 5,000 feet over the same time period, and that four times as much horsepower per rig is being used compared with 2004. Halliburton is shifting some capacity to oil basins with success.

Spears & Associates Inc. estimates nearly 16,000 horizontal wells were drilled in 2011. Though a record, it will be short-lived, as it estimates close to 19,000 wells will be drilled in 2012.

"These fleets are not looking for work, they are committed to customers and have or will displace competitors in those liquids plays," Lesar said.

The downside for service companies when shifting to new areas is the impact to short-term margins as local crews are trained and learn the new reservoir. Tim Probert, Halliburton's president of strategy and corporate development, said that eight crews would move from gas to liquids basins, primarily into the Rockies' Niobrara and Bakken shales and liquids-rich portions of the Marcellus, but there were other areas that were perhaps "not on the radar yet," to which the company might move equipment.

Lesar is confident the industry will not see a collapse in pressure-pumping margins in North America, as liquids plays are more equipment-intensive, and he anticipates more rigs will be added to oil plays in 2012.

Analysts are not so sure there will be a rebound to peak levels, however. Bernstein Research's recent Commodities & Power note suggests recent margin pressures are a harbinger of the end of peak profitability in the sector.

While margins may be falling, returns are still strong for now. This continues to drive start-ups in the space. Pricing is already leveling off in some basins, and Bernstein analysts expect capacity additions to come into play just as the industry begins to regain efficiency after re-allocating equipment, towards the middle of the year.

"In dry-gas basins there has been significantly more pressure than in liquids basins," echoed Probert. Halliburton is working to lower its cost of delivery and increase efficiency. Innovations like sliding-sleeve technology have led to a 10% reduction in crew size for Halliburton, he said.

Logistics in proppant supply had been a problem for Halliburton, which had experienced disruptions in the Bakken, Rockies, South Texas and the Permian Basin. These difficulties went hand in hand with cost increases for proppant that could not necessarily be passed through at the time.

Other indicators, such as cost-per-horsepower and delivery times, are also decreasing, according to Daniel. Companies that can build equipment in house are seeing a 20% to 30% cost reduction over the industry average, which currently is $1,000 to $1,100 per horsepower. Lead times for equipment have fallen significantly, spurred by new entrants into the market and capacity additions by existing players.

"We had the opportunity to tour several prominent equipment assemblers, some of whom could make deliveries in late spring if I ordered mid-January," says Daniel. Another builder had over a dozen pumps ready to sell.

Despite heavy wear and tear, the industry has yet to see much in the way of fleet retirements.

"Public companies haven't formally announced any significant fleet retirements. They talk about the need to do so, but components on a frac trailer fail and can be repaired and replaced in-situ. Sure, there is downtime, because 24-hour uptime is hard on equipment," says Daniel. He puts downtime at 10% to 20%.

The result of these supply-chain improvements is that E&Ps may not be waiting as long for frac dates this year as they once were.

"What was once the advantage of the pressure-pumping industry is becoming the advantage of the E&Ps," says Daniel.