It was a startling comment. At the IHS CERAWeek energy conference in Houston, the top gun at an international major said, in this most prestigious public forum no less, that oilfield services and other costs are too high, and he won’t pay any more. He frankly warned the service sector to rein in its costs, or else the current level of E&P activity could not continue.

“Energy has a great future if we control our costs. But what we are delivering today is too expensive. We have to go to the sub-sub-sub-contractors and tell them we can no longer be the deep pocket,” Christophe de Margerie, chairman and CEO of Total SA, said. “We cannot continue to swallow this huge cost inflation.”

In another session at CERAWeek, his peer, Yves-Louis Darricarrère, president of upstream for Total, said costs are “escalating to the point where sustainability is at stake.” He said Total’s return on capital employed (ROCE) fell from 16% in 2012 to 13% in 2013. “We wonder if our investment risks are adequately rewarded.”

Indeed, the dilemma of ever-higher costs for exploration and production was a frequent theme at the March event. IHS CERA reports that in the past three years, costs in unconventional plays alone have risen 48%.

But, we have to look more closely to see what’s really going on. Huge LNG export projects in Australia, for example, have been plagued by headline-making cost overruns in the billions of dollars, skewing the global cost averages. Down Under, it is a matter of tight labor markets and tough logistic supply chains—although some observers claim poor advance planning is also a major culprit.

Of course, complaining about service costs is nothing new. But in recent years, the high demand for frac crews, purpose-built rigs and compression equipment has escalated costs, until the service sector recently added capacity. The high cost of applying more technology solutions is worth it, but it does cost more to deploy micro-seismic arrays, advanced frac tools, zipper fracs and so on. Pad drilling ultimately reduces the per-well cost by increasing well recovery, but operators still have to spend a lot up front before they start getting cash flow back out.

A lot of science is going on in the field, perhaps more than investors realize, but it comes with a price—money and time. This was detailed at the recent AAPG Eagle Ford conference in February. “Identifying the best predictors of well success area-by-area is a time-consuming and expensive exercise … ,” wrote the Jefferies & Co. research team.

Companies talk about transitioning to a manufacturing process that will soon reduce costs and hike production, but this is not going to be quite as simple as it sounds. “Industry is trying everything,” the Jefferies report said when listing its major takeaways from the conference.

R&D is taking place regarding type of proppant, well spacing, frac spacing, perf clusters, length of the lateral and more. E&Ps have found that a standardized process, such as having the same number of frac stages over a given lateral length, will not be effective if the process is not tailored to the specific well location and area geology.

It appears that the correlation between well results and frac spacing is higher than the relationship between well productivity and type of proppant used during the frac.

“Presenters all agree that shale success in the manufacturing phase will require much different skills than in the discovery/delineation phase. Identifying what the best operators are doing differently and quantifying the success remains a challenge,” Jefferies said.

These themes were repeated at Raymond James’ 35th annual conference.

“Much of the focus is on returns with increasing efficiencies on core acreage through 1) longer laterals, 2) bigger fracs, and 3) further downspacing. The improved efficiency of horizontal drilling is well-documented and has proved fruitful in shale plays across the country. Companies seem to be of the opinion that increased proppant volume per stage could con- tinue to provide for increased returns.”

On a weekly basis, Global Hunter Securities compiles data for 87 E&P companies on their margins, F&D costs, the ratio of cash to capex, leverage and many more metrics, some 110 in all. What do these data reveal?

For one, over-spending continues unabated. The median capex-to-cash flow ratio is 143% and the average is 226%. These ratios are even worse the smaller the E&P company. If the land rush is over and the aggressive drive to hold acreage by production is winding down, then why are so many E&Ps still outspending cash flow? For one thing, they always have. But, is this a good business model now that the industry has entered the harvest (manufacturing) mode in most plays?

In the Global Hunter database, we see E&Ps with net debt that’s three or four times EBITDA, still outspending cash flow by literally billions of dollars. This is not sustainable, no matter what price the service companies charge their customers

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