Musings: Shale Alters Energy Market, But Players Face Challenges
Additionally, there has been a huge wave of private equity money seeking to participate in the shale revolution. New companies backed by private equity funds were formed. At one point several years ago, we had a discussion with an A&D professional (acquisition and divestiture of producing assets) who said that all the properties she had for sale were conventional oil and gas wells and prospects, including entire portfolios of private equity-backed companies who were convinced that unless they were 100% focused on shale, it would be impossible to tap public capital markets. The flood of private equity money into the oil and gas producing sector, as well as the oilfield service industry, is being driven by the promise of a future natural gas and crude oil bonanza. That may prove to be a risky strategy, however.
Forecasters around the world have declared America to be the new Saudi Arabia and a disruptive force in OPEC’s and Russia’s future. Moreover, the supposed 100 years of U.S. natural gas supply suggests that new gas markets for vehicle transportation fuels and liquefied natural gas (LNG) exports offer huge profit opportunities. Rising global demand for American shale gas could lead to higher domestic prices bringing producers huge profits. Of course that potential bonanza has triggered a debate over whether the United States should allow natural gas exports, or whether by restricting them we ensure low gas prices for a long time and enhance a revival of the American manufacturing sector with its large job-creating power. Only time will tell. But we do know that piles of private equity money are resting on the sidelines awaiting new opportunities to invest in the shale revolution. How can they do otherwise given the promise of long-term rewards?
The love-affair with the shale revolution, even though its financial rewards have not been prolific, has created a dilemma for all oilfield service companies, but in particular the contract drillers. The decline in natural gas prices since 2009 has forced operators to focus on cutting costs in their shale programs. The first reaction of producers to falling prices was to shift from drilling dry gas wells in favor of crude oil and liquids-rich targets. Simply put, these latter outputs earn higher prices, thus providing greater profitability for producers.
For those who could not completely shift their business focus, the pressure of low gas prices has become a significant driver to lower field costs. Much can be, and has been, done to reduce drilling time through greater use of seismic data, better understanding of the various formations to be drilled through to reach the target formation through downhole telemetry devices, improved bits and drilling fluids, better directional drilling hardware, and the use of drilling pads to reduce rig moving time.
Significant improvements have been made in downhole drilling and completion software and hardware. Many of these improvements eliminate or reduce the input of humans. The same thing is going on above ground. Pad drilling reduces rig mobilizations and well stimulation setup times, saving time and expense. Additionally, the industry is working toward developing fully-automated drilling rigs, i.e., rigs without human control. While that goal still remains in the future, there have been significant improvements in drilling time – known as rig efficiency. There has been so much improvement that Nabors Industries (NBR-NYSE) even cited drilling efficiency for creating a problem for producer capital spending during the second half of this year. Since wells are being drilled much faster than in the past, producers are spending their budgets faster and will exhaust their authorized funds much earlier in the year than normal. A recent exploration and production company spending survey projects that instead of a 0.8% decline in U.S. capital spending in 2013; it will fall by 2.6%. If true, drilling activity in the fourth quarter could become a rarity. Another survey says spending will increase.
Faster drilling means that the cost of rig time per well is reduced, but the amount of money spent on drilling consumables along with drilling and completion services remains constant for each well. If a rig is on a term contract (one year, for example) there is no savings on this cost component when drilling wells faster, but since all other costs remain stable for each well drilled, the more wells, the greater the cost. This is why improved rig efficiency is consuming capital budgets faster. This is not good news for drillers who are finding that fewer rigs are needed to drill the same number of wells each year. Unless capex budgets expand, the drilling rig count is unlikely to improve during the balance of this year and it raises questions about the pace of drilling and the number of rigs needed in future years.
Longer term, the unanswered question for drillers is what will the rig fleet of the future look like? How big will it be? What types of rigs will be needed? If the future of North American drilling is truly all about shale, then a certain rig fleet profile is dictated. On the other hand, what happens to that profile should shale prove less successful requiring greater drilling for conventional resources? Can we learn anything from examining the history of the evolution of the domestic rig fleet? Has there been another time in history when the drilling industry confronted a similar market and equipment shift in response to changing market trends? To examine the rig fleet we have relied on the annual rig census now compiled by a subsidiary of National Oilwell Varco (NOV-NYSE). While the survey originated in 1955, it was not as detailed then as now. Additionally, the survey was not conducted in 2002; therefore we have a one-year break in all the charts.
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