The iconic riveted denim jean, Levi's, was patented in 1873 during the California gold rush when a tailor from Reno, Nevada, partnered with Levi Strauss in San Francisco to provide a sturdier type of pant that would hold up in the grueling conditions of the mining camps.

Today investors still cite that example when they ask, who would you rather be: the man panning for gold who may not hit it big, or the man who supplies the picks, shovels, tents and jeans? The latter struck it rich.

The analogue to the oil and gas industry is easy to see. The count of drilling rigs may have flattened in most basins thanks to the advent of pad drilling and batch completions, but the intensity of work demanded from fracture stimulation crews keeps going up, as the well count rises with downspacing.

The number of wells drilled and the number of hydraulic fracturing stages made during completions continues to climb dramatically. In some plays, such as the Montney in Canada and certain U.S. basins, operators are demanding—and getting—the capacity to do as many as 80 fracturing stages per well. If an E&P company plans four wells on a pad and operates four pads, the math adds up quickly—as does the backlog or wait time.

The E&P industry faces the twin challenges of creating higher rates of return while continuing to deliver production and earnings growth. Likewise, the service industry it relies on is fighting its own battle to match equipment, crew capacity and consumables to the ever-higher need.

Like an insatiable shark that has to keep moving to eat, it has to move continuously. “We are at an interesting point in time,” said oilfield analyst Jim Wicklund, managing director of equity research for Credit Suisse in Dallas.

“In the past when costs went up, E&P companies would ask suppliers to lower their prices by 10%. Now, the E&Ps are saying, ‘You’ve got to figure out a way for me to cut my cost per boe [barrel of oil equivalent]. Use whatever you think you can bring to bear to lower my costs—but increase my IPs [initial production rates], my EURs [estimated ultimate recoveries]. Don’t just lower my costs, improve my economics.’ Everybody is being judged by their returns, not growth.

“That’s a very different conversation. It’s a sea change in the dialogue between the two industries.”

The talking points in this dialogue are greater need, but at lower prices. “The thing our members hear from their customers is, you need to drill and complete wells more economically and make sure this growth engine continues to run,” said Paul Coppinger, president of the Petroleum Equipment and Suppliers Association (PESA) in Houston.

As president of Weir Oil & Gas, the largest independent U.S. manufacturer of pressure pumping units and cementing equipment, Coppinger is doing his part to add capacity. In 2010 and 2011, Fort Worth-based Weir quadrupled its workforce. When gas prices fell in 2012-2013 Coppinger slowed the company’s pace, but the Weir hiring ramp-up is continuing this year, he said.

“We’re seeing more inquiries from customers, and our backlog is growing as these horizontal sections get longer and there are more stages to frack. In a higher-priced oil and liquids environment, where people are drilling that more than natural gas, we are using more quinteplex [five-piston] pumps [adding to the complexity].”

Analysts say service companies that offer some kind of differentiated technical edge, and an integrated approach, are the winners. Instead of an E&P approaching Schlumberger (NYSE: SLB) for one service, Weatherford (NYSE: WFT) for another and Halliburton (NYSE: HAL) for others, and managing the logistics this implies, efficiency gains can be had by relying on one company to do it all. “The analogue is that I can sync everything between my iPhone, my iPad and my Mac,” Wicklund said.

In the midst of these trends, investors in the service and supply segment have enjoyed themselves for the past 18 months—until, that is, the stock market downdraft that occurred in the last week of July led to profit-taking. Prior to that, the Oilfield Service Index (OSX) had risen steadily since January. Certain hot sectors such as the frack sand providers had risen even more. U.S. Silica Holdings (NYSE: SLCA) rose from $21.65 to $63.25 in the past year. Hi-Crush Partners LP (NYSE: HCLP) rose more, from $20.26 to $69.25. Emerge Energy Services (NYSE: EMES), which also supplies premium sand, rose 140%.

Wicklund remains enthused. “For the first time in history, I have a BUY on the Big Four [Halliburton, Schlumberger, Baker Hughes (NYSE: BHI) and Weatherford].”

What lies ahead varies by basin and operator, but it looks like drilling and completion activity will continue to increase. Cowen & Co.’s midyear spending survey update indicated U.S. capex will rise 9% this year, Canada’s by 7%, and possibly by double digits in 2015 in both countries. One factor in this trend is the large E&Ps that continue to shift resources back to the U.S., away from international arenas.

“We polled 475 E&P companies and we find their budgets are still conservative, but they are leading to growth," said Jim Crandell, Cowen's lead service analyst. The outlook for service costs varies by product line and type, but in general, he sees higher costs ahead.

"A 10% gain in spending, given the efficiencies we have today, yields an increase in completions of 14% and in frack stage counts of about 20%. Just the use of new AC-drive rigs and 24-hour frack crews make a big difference," he said.

"For service companies, profit margins are off their lows, but they are not yet where they were at the peak, when we saw margins on a frack, on an EBITDA basis, of 25% or 30%. Today those frack companies are averaging around 10%. It's a business where utilization hasn’t improved enough yet to drive margins up.”

It appears that service costs have bottomed and are rising again after a three-year decline. This isn’t good news for the average E&P, especially in light of a recent IHS study of more than 80 oil and gas companies. It showed that cost escalation is a continuing problem and that E&P returns are lower today than they were in 2001, when oil prices were far lower than they are now.

“While returns have increased in recent years, costs have accelerated at a rate that has squeezed margins. The more than $60 per barrel increase in global oil prices since 2002 has been offset by significantly higher costs,” said IHS analyst Nicholas Cacchione in the report.

The efficiencies that E&Ps gain are rising dramatically, but despite saving some money, they do not have infinite drilling budgets, Wicklund pointed out. “It really means I [the service company] can frack 20 wells in a very short period of time, and while you are now tapped out, I can go find another customer,” he said.

“We did a research report that showed you can drill a well in half the time you could three years ago. But that doesn’t mean E&Ps are able to drill twice as many wells now—they don’t have the budget. But they can drill that 11th or 12th well after the 10th is done—that’s where the savings come in."

The rig contractor doesn't have to drive the crew and equipment to four corners of a lease, if it can drill all the required wells from a central pad. Work can be done fast ... but that also means a rig is not being paid a dayrate for 12 days to reach total depth, if it takes only five. The utilization of equipment is up, whereas before, the mobilization and "de-mobe" time got in the way.

Service companies are doing all they can to salvage the returns of their E&P customers, Wicklund believes. "But costs will continue to go up. E&P companies operating in the least-core acreage will suffer, and the ones that employ a new technology the best will be the relative winners."

Thirst for technology

Dan Themig, co-founder and president of privately held Packers Plus, which designs openhole, multistage frack systems, says customers are demanding as they search for hydrocarbons. For example, in 2010 the company successfully stimulated a 60-stage job in the Marcellus Shale at the request of a customer.

“This industry is driven by a thirst for technology,” he said. “The CEOs tell us they want zero failure on downhole tools. Second, they want to do more stages with more intensity. Third, they want more efficiency—such as doubling the stage count in a well, but increasing our time on location by only 20%.

“Every time we make a technical leap, they have another one on their wish list right behind it. If there is one trend I could identify, it’s great increases in frack intensity. We are going from pumping 20 stages to 60 and more, and it’s just going to double the time a frack crew is on location.”

Themig said he sees the phenomenon in the Niobrara and Bakken, and he’s starting to see it in the Haynesville and some areas of the Eagle Ford.

A completion that formerly took three or four days on one well could potentially take up to 100 days, he cautioned. “We had one operator who wanted to go with these high-intensity fracks on a fieldwide basis, but what he quickly determined was that there wasn’t enough equipment in that basin to do it, and maybe they didn’t have enough staff to oversee it.”

Companies are experimenting with coiled tubing-conveyed fracturing that is faster than the plug-and-perf method, and new ball-drop technologies can reduce frack time by as much as 60% to 70%, only ratcheting up the speed of activity.

Packers Plus has technology that can open multiple intervals simultaneously, so if it is doing a 30-stage frack sequentially, it can pump three stages at the same time with about equal frack volumes in each interval—again, speeding up that time to net present value.

To keep up with demand, in the past year the company has added robotics to its manufacturing plant near Edmonton, Alberta, and it has expanded its Houston facility.

But gaining efficiency in fracturing is still a Holy Grail for the company and its competitors. If one frack stage on a multistage job fails, the cost is high.

Experts realize that in any fracturing situation, some of the fracks do not do what they are intended to do, and others contribute little or nothing to increased oil and gas production.

Fracturing expansion

For the members of PESA, finding enough people to hire is a big hurdle, said Coppinger. “It’s not insurmountable, but it is a challenge.”

He estimates some 17- to 17.5 million hydraulic horsepower (HHP) is installed in the U.S., versus 16 million in 2012. “It’s probably doubled in the last five years. It was definitely below 10 million HHP. The ramp-up has been dramatic, and with this shale revolution, our PESA members are challenged to make sure they have enough talented people going forward. We’re going to need tens of thousands of pumpers coming into our organizations.”

To that end, PESA now co-sponsors, along with IPAA, five petroleum academies, four in the Houston school district and one in Fort Worth.

R.W. Baird recently expanded its oilfield service coverage, and in an early August note it highlighted the continued growth in the frack fleet. Weatherford has added 200,000 HHP year-to-date, C&J Energy Services (NYSE: CJES) will have added 100,000 by year-end and Schlumberger has deployed eight new spreads this year. Patterson-UTI (NASDAQ: PTEN) has 115,000 HHP on order.

Halliburton has earmarked $300 million to speed up additions to its fleet and is delaying the retirement of some legacy units. On its second-quarter conference call, executives said it had to turn down work during the quarter because it was short on frack crews.

“It is important to note that this new capacity is already contractually committed,” noted RBC Capital Markets’ Kurt Hallead, global co-head of energy research, in a July report on second-quarter service company results.

Factors in pricing power

Operators in the U.S. have identified about 25 years’ worth of drilling locations, and as Wicklund said, “The outlook is fabulous. The U.S. is going to be the best sector of growth in the world for the next five or six years.”

Demand is speeding up for services, equipment, sand and crews. Pricing is improving in the red-hot Permian Basin and Eagle Ford theatres of activity especially, he said. Mid-tier pumpers are leading the way.

Increased well density in each shale play, more frack stages per well and slickwater fracks are driving the sand market to new heights. Suppliers are scrambling to keep up. Completion pricing had come down in some basins because a lot of capacity has been added in the past two years.

But Hallead thinks we are at the leading edge of new price increases; for one thing, service companies’ existing contracts roll off at year-end, with negotiation for higher prices on the horizon. Their calendars are full through year-end and beyond. Most equipment available on the spot market is confined to the Permian Basin, where demand soaks it up readily.

“The one thing I heard pretty consistently in the second-quarter conference calls was ‘revenue intensity per well,’ and that’s coming in the form of more stages and more proppant per stage, and the requisite horsepower on location,” Wicklund told Oil and Gas Investor.

“The interesting dynamic to me is we haven’t seen a big difference in cost per well, which is counterintuitive. It’s a bell curve, and it still depends on the operator, the acreage, the basin. But we believe pricing power is inevitable,” he said.

“Frack fleets are now being locked down for three to four weeks at a time with stage counts regularly exceeding 30 per week (up 25%). The Permian is the primary driver. Spot pricing is moving higher, and we expect more significant P&L impact in 2015 after contracts roll over later this year,” Hallead wrote in a report.

Hallead said the supply of equipment and crews is chasing the demand curve upward. On its second-quarter conference call, Halliburton said it would add 1 million HHP now and into 2015, all already contracted; nine months ago, it was predicting 500, 000 HHP. Halliburton has said the frack of the future will reduce the amount of equipment and number of people on location by 20%.

But for all these companies, analysts cautioned, margins may not improve much, if at all, because of the cost of adding manpower and consumables, as well as higher expenses for logistics.

The duration of these pricing cycles is always the question, Hallead said. “Seeing the turn is one thing and getting the duration right is the challenge. Usually it’s a two-year upcycle and one year down. Now we are coming out of a two-year downcycle due to low gas prices, so the industry will chase it back up.”

M&A and IPO trends

Although several large service and supply mergers have been announced, Hallead thinks there could be more, as well as more IPOs in the sector.

It’s rare for there to be mergers during a cycle low because most service company buyers won’t pay that much for upside, he noted. “Now there seems to be more confidence that the cycle is heading up, so the bid-ask spread is coming closer together,” he added.

The merger of Nabors Industries’ (NYSE: NBR) completion and production business into C&J Energy Services for $2.8 billion is an example. C&J provides fracking, coiled tubing, wireline and other services. Its stock had nearly doubled in the past 52 weeks before this deal was announced.

There may be some roll-ups of smaller service firms and private frack companies, and some service IPOs ahead, he said. Private-equity-backed Fairmont Minerals Ltd., one of the largest sand providers, is considering a $1 billion IPO. It owns Santrol.

Cowen’s Crandell noted that there are some 80 frack businesses in the sector, many being “Mom and Pops” running only one or two frack spreads. Several are backed by private-equity players looking to cash out. “There is a lot of activity bubbling below the surface,” he said, “and I think we’ll see a handful of IPOs this year and more next year … for frack companies, land drillers, coiled tubing.”

An increase in slickwater fracks is leading to more demand for raw sand that could push prices higher. In all cases, visibility on the frack calendar in coming weeks and months is excellent. Sand supplier Hi-Crush Partners LP announced recently it has extended its contract with Halliburton through year-end 2018 and stands ready to provide more frack sand if Halliburton’s demand for it increases. Analysts noted that this was Hi-Crush’s sixth contract announcement in three months.

Emerge Energy Services, the frack sand MLP, plans to double its capacity by 2016, and with 40% of that not yet contracted, it could take advantage of the frack sand spot market, Crandell said.

Halliburton owns or has leased some 6,000 railcars to move equipment and sand around the country. Hi-Crush will control 7,000 railcars by the end of this year, sources said.

Land rigs, land rush

When Patterson-UTI reported second-quarter revenues of $757 million, it said revenues and margins improved across both the drilling and pressure pumping segments. Thanks to strong customer demand, the company has ordered an additional 115,000 HHP of frack equipment on top of 40,000 HHP that was already on order. This total would constitute three frack spreads plus spares. The three spreads are supposed to be delivered starting in fourth-quarter 2014 and on into second-quarter 2015.

In addition, it has 20 newbuild rigs coming this year.

Indeed, Credit Suisse’s Wicklund estimates 100 to 150 new land rigs will be delivered to the market this year and next, and most have already been contracted for by E&P clients. What’s more, these are adding to the U.S. rig fleet, not replacing older iron. He thinks rig “retirements” could start in 2015. Hallead pegs the number of rigs added as closer to 200 in 2015.

“We expect industry cash margins to continue to expand through at least the end of 2015 due to the extremely tight AC rig market,” he said. “We think dayrates can top out at plus $30,000 a day in this cycle.”

The efficiency of these new rigs has been well-documented and constitutes a big win for the E&P industry, making them
probably worth higher dayrates, analysts say. A Tudor, Pickering, Holt & Co. report said among the major horizontal basins, “We saw up to 14% year-over-year improvements during Q1, but noticed the improvements were more varied across basins and less dramatic vs. the 10% to 20% year-over-year gains seen in the first half of 2013.

“Going forward, we believe the Permian represents the largest opportunity for additional improvements in drilling efficiency as the median horizontal spud-to-rig release time during Q1 was 26 days vs. the Eagle Ford at 14 and Williston at 18. We think the overall industry will trend towards plus or minus 10% horizontal drilling efficiency gains for 2014 …”

Helmerich & Payne has announced long-term contracts for 74 new FlexRigs it is building in fiscal 2014, and it has upped its manufacturing pace to four rigs per month. This is the third time since 2006 that it has stepped up to this pace.

Managing around logistics and bottlenecks is still a concern for executives on both sides of the table. E&P companies are driven to speed up net present value and boost IP rates, and as NPV is mostly garnered in the first three years of a well’s production life, the companies are trying to get that out of the ground faster.

There is a constant push and pull between what service companies think services should cost and what E&P procurement officials are willing to pay. For service companies, the challenge is to improve profitability and cash flow where they can, and if they have a better technology or a differentiating service to offer, they may have some pricing power. “You are not going to get a price increase on older technology, although R&D is continuing,” said Cowen’s Crandell.

PESA’s Coppinger thinks capacity is available, or can be added. “There is plenty of capacity, and if there’s not, we as manufacturers have the ability to add to it. You can be assured that if our customers need to frack more wells, we can support that. I think 80% of the rigs are drilling for oil today, and if you still need that, but add back in more gas rig demand, there will certainly be an uptick and in certain areas, yes, price increases.

“So there’s a tug of war going on here. In 2010-2011 the service companies were winning, but today the E&P companies are winning. It’s a supply and demand issue.”

The future looks bright for upstream companies, according to Crandell. “For the E&P sector, it really is a golden era,” he said. “If you have the acreage, the prospects and the expertise, these companies are doing exceptionally well. You are probably not looking at large cost increases, nothing that significant. I see only moderate cost pressure in the coming year.”