US unconventional oil responds to low-price environment

June 1, 2015
Deferred and cancelled investments in US shale oil fields could in 2-3 years begin creating an environment in which new supplies are less plentiful, causing baseline oil prices to move closer to $100/bbl.

Gabe Collins

Baker Hostetler LLP
Houston

Deferred and cancelled investments in US shale oil fields could in 2-3 years begin creating an environment in which new supplies are less plentiful, causing baseline oil prices to move closer to $100/bbl.

The current economic environment makes this difficult to see. North American crude output remains robust despite falling rig counts, storage levels are high, and core producers from the Organization of Petroleum Exporting Countries (OPEC) continue to maintain high export levels.

A range of market participants including exploration companies, midstream infrastructure operators, and service companies is grappling with this uncertainty as they respond to low prices and higher volatility. Market participants are striving to ascertain how the US unconventional oil sector will evolve in the next 1-3 years, as this will affect global crude and liquids markets. The US shale natural gas industry's response to a price crash caused in large part by its own output gains may help shed light on this important question.

This article addresses four core lessons from the US shale gas sector's response to low prices and explains how circumstances differ in the US oil patch:

• US unconventional oil producers have less upside for productivity gains now than did shale gas producers 2008-12.

• New drilling will be more dense with longer laterals and larger fracs.

• One successful play can drive production growth on a national level.

• The US is becoming the primary global swing producer of crude, which will increase price volatility. This will affect investment in new production worldwide for the next 3-5 years, setting the stage for a return to $100/bbl oil.

Price cycles

This is not the first time US unconventional oil and gas producers have drilled themselves into a price crash. The recent growth of unconventional oil in the US and its effect on commodity price bear similarities to that of shale gas less than 10 years ago.

Beginning in 2006 production climbed sharply in the Barnett shale.1 Initially, the market showed little change and gas prices continued rising. Henry Hub natural gas prices peaked in late 2008 at $12.69/MMbtu, fell precipitously in 2009, and then rarely exceeded $5.00/MMbtu for the next 6 years. Between September 2008, when the number of gas rigs in the US peaked, and November 2014-the latest comprehensive data release from the US Energy Information Administration (EIA)-the number of gas-focused rigs in the US plummeted by 78% but gas production still rose by 47% (Fig. 1).

For crude oil and liquids, US production began to climb in late 2011 as producers focused on liquids-rich unconventional plays to offset the shale-driven natural gas price decline.2 By late 2014, after the shale industry added nearly 3 million b/d of additional oil production, crude prices began to crash.

Despite the historical parallels in boom-bust timing, US oil producers will likely not increase production despite lower prices as did gas producers after 2008.

Less upside

Unconventional gas producers were better placed to boost productivity in 2008 than oil producers are in 2015. The real shale revolution for US gas producers resulted from becoming so productive they could sustainably sacrifice price for volume.

Productivity in the major shale gas plays, led by the Marcellus, accelerated sharply beginning in early 2011, about the same time that unconventional liquids production took off. For the 18-month period between June 2011 and January 2013, the average Henry Hub gas price was 30% lower than the starting price in June 2011, yet Marcellus drillers' productivity rose by 213% (Shaded bar Fig. 2).

Productivity numbers in the Bakken, Eagle Ford, and Marcellus rose on a remarkably similar trajectory beginning first-quarter 2011, suggesting a high degree of technical cross pollination between basins (Fig. 3). Large pressure pumpers-a handful of whom dominate the US fracing market-are the logical source of this technology transfer.

Proppant use data from key plays support the technology transfer thesis. Data from IHS PacWest show that the proppant volume used per well in the liquids-focused Eagle Ford shale rose by 80% between first-quarter 2011 and second-quarter 2014, while proppant volume per well in the gas-focused Marcellus shale increased by 82% during the same period.

The rapid increase in oil productivity happened during a period of high prices in an effort to maximize economic returns. Shale gas producers' productivity enhancements, however, arose out of a struggle for survival as producers coped with low gas prices by emphasizing volume over price.

The simultaneous productivity improvements by unconventional oil and gas producers 2011-14 resulted from a common set of techniques: longer laterals and larger fracs. Because these technologies expanded in both sectors simultaneously, there no longer exists a wide margin for efficiency gains through their use on a per-well basis. This suggests that relative to gas producers 7 years ago, the unconventional oil sector now has much less ability to increase productivity to help it cope with low prices.

Oil producers still have room to enhance economic returns at lower price levels through incremental technical improvements and lowering costs. But the deep penetration of enhanced drilling and completion techniques in virtually all large liquids basins other than the Permian means oil producers are less likely to reap the benefits of disproportionate productivity increases that could sustainably boost output despite unfavorable prices.

Producer responses to the current low price environment already point toward a flattening or decline in US crude output through the next 6 months and suggest an upwards crude price turn will occur sooner than expected. EOG Resources Inc., Continental Resources Inc., and other operators have been deferring completions, effectively transforming new, uncompleted wells into storage that can feed oil into the market with as little as two weeks' notice once prices recover.3

Completion deferrals are essentially a bet that crude oil prices will rise in the near future, making it worthwhile to bank oil in the ground until WTI crude prices move higher than $60/bbl and service companies reduce completions costs by 15% or more.

Drilling density

Horizontal wells offer substantial potential for efficiency gains through longer laterals and improved fracing techniques, tactics that vertical wells typically cannot use. For example, Pioneer Natural Resources Co. says that it has optimized its Eagle Ford shale completion program by spacing wells more closely and using larger volumes of proppant.4

In Pioneer's case, a 4% increase in drilling and completion capital spending can boost ultimately recoverable oil by 20% and a 12% increase in capital spending can raise estimated ultimate recovery (EUR) by 30%. Not every shale driller has cracked its core plays' code to the degree Pioneer, EOG, and other top-tier operators have, and not all operators have access to low-cost captive frac sand supplies as do Apache Corp., EOG, and Pioneer through their sand mines. But there remains substantial room once prices improve to accelerate completions and obtain increases in ultimate oil recovery relative to capital spent.

Efficiency gains in the Eagle Ford shale began in 2012 as the rig count remained static while production continued to rise rapidly despite the sharp decline in crude oil prices beginning third-quarter 2014 (Fig. 4). The Marcellus shale experienced an even more profound boost in production relative to the rig count-nearly twice the Eagle Ford's rate-as operators drilled longer laterals, increased frac stages, and moved to pad drilling due to the region's hilly topography.

For example, Range Resources Corp.'s average lateral length in the dry gas region of Southwest Pennsylvania was about 3,000 ft in 2013, rose to more than 5,000 ft in 2014, and will likely climb to more than 6,000 ft in 2015.5 In addition to longer laterals, which provided more reservoir access, thereby boosting output, pad drilling reduced costs by allowing operators to drill multiple wells from a single location. Pad drilling also reduced the time needed to build locations and move rigs in the rough and hilly terrain of Pennsylvania.

One stellar play

Rising shale gas production in spite of low prices was born of a serendipitous union between engineers and Marcellus reservoir rock. The Marcellus contains an immense amount of hydrocarbons per square mile and these gases and liquids readily respond to the large, multistage completions now used in the play. Producers report numerous wells with initial production (IP) rates exceeding 30 MMcfd (the energy equivalent of more than 6,000 b/d of crude oil). Range Resources' top Marcellus well to date-the Claysville Sportsman's Club 11H-yielded an IP rate of 59 MMcfd (equivalent to 10,200 bo/d).

Without the Marcellus, US gas production would have actually declined 2011-14 (Fig. 5). The Marcellus's geology drives this singular productivity. Historical production analysis of thousands of Marcellus wells suggests that wells in the sweet spots of the play decline far more slowly than wells in other gas plays such as the Haynesville shale. A Morningstar study of nearly 4,500 Marcellus wells in Pennsylvania found that the production rates of wells in Greene, Susquehanna, and Wyoming counties actually increased by as much as 10-30% during their first 6 months online.

No such phenomena seem to exist in liquids-rich plays, where steep decline rates are the norm. This strengthens the case that oil producers will be incapable of boosting production in the face of low prices as their shale gas peers did. Such geological realities mean that shale oil producers are in a faster drilling and production loop than gas producers and will have to drill many more wells to expand production.

Permian growth

The Permian basin has the largest absolute production growth upside of the major US unconventional oil plays. During the first years of the shale revolution, drillers in the Permian remained heavily focused on vertical wells. The past 4 years show a decisive shift to horizontal drilling, with about 74% of Permian rigs now targeting horizontal prospects (Fig. 6). Daily oil production in the basin has risen from 980,000 b/d in January 2011 to 2,037,055 b/d in April 2014, according to EIA.

Operators in core Permian counties such as Midland have turned predominantly to horizontal drilling in the past 12-18 months as they work to access rich, multilayer stacked plays. The oil price crash has only accelerated this transition. Producers such as RSP Permian Inc. are now experimenting with long lateral wells (up to 9,500 ft) in layers such as the Spraberry, which formerly was only drilled with vertical rigs.6 RSP Permian's Spanish Trail 218 featured a two-well pad drilled into the Middle and Lower Spraberry formations, according to the company's March 2015 investor presentation. The wells had an average lateral length of 9,950 ft and the 30-day IP rate averaged 1,192 boe/d, multiple times more productive than comparable Spraberry vertical wells.

Horizontal efficiency

As horizontal plays move from exploration and delineation into full-scale industrial development, operators can extract efficiency gains. EOG reduced its drilling time by 23% in 2013 and a further 18% in 2014 in the Eagle Ford shale. The company also sliced 29% off its average Bakken drilling time in 2013 and 25% in 2014 (Fig. 7). As more Permian basin operators move into full development later this year and into 2016, similar productivity gains are likely and the slowly rising Permian productivity curve shown in Fig. 3 will climb more steeply.

Improvements will come from more than the drilling side alone. The same techniques of longer laterals, upsized fracs, closer well spacing, and pad drilling used in the Eagle Ford, Bakken, and Marcellus are becoming widely adopted in the Permian and the current low-price environment will only speed this process.

Cimarex Energy Co. now drills wells in the Wolfcamp D layer in Culberson County, Tex., with 10,000-ft laterals with up to 43 frac stages.7 The company reports that these wells have a pre-tax internal rate of return of 52% at $40/bbl realized oil prices, illustrating the appeal of lengthening laterals and pumping bigger fracs.

Some Permian operators already report a decline of more than 20% in core service costs, such as pressure pumping. This trend will enhance the appeal of drilling longer laterals with more proppant, given the disproportionate returns such incremental investments yield.8 Concho Resources Inc. has reported that its upsized fracs in the Northern Delaware basin's second Bone Spring layer yield a 75% increase in output over the wells' first 180 days of production.9

In conjunction with longer laterals and bigger fracs, operators are also spacing wells more closely and concentrating development in production corridors to maximize efficiency. EOG has decreased its well spacing in the Delaware basin's Leonard shale from 1,030 ft in 2011 to 560 ft in 2014 and is experimenting with spacing as tight as 300 ft in some areas.10 Tighter spacing and the prevalence of multiple producing layers accessible from a single well pad also lend themselves to production corridors such as those Laredo Petroleum Inc. is now developing. Its planned corridors would feature hundreds of wells served by common oil, water, and gas takeaway infrastructure and we expect other operators will also use the concept to enhance production efficiency.

As Permian drillers apply and refine techniques pioneered in the Eagle Ford and Bakken, the basin could add more than 1 million b/d of incremental crude and liquids output by 2020. Higher than expected crude prices caused by oil production problems overseas or stronger demand would increase potential Permian production.

New global swing producer?

OPEC is losing control of the global market as North American producers move themselves further down the global cost curve. Many North American shale producers are no longer the marginal, high-cost global barrels. Low prices are simply making the strong companies stronger. EOG reports it now makes better returns at $65/bbl oil than it did at $95/bbl oil in 2012 and we suspect other producers are making similar strides.10

US shale plays will never be as low cost as most core OPEC production, but they will increasingly be able to operate economically at a price point incompatible with the long-term budget needs of Saudi Arabia and other OPEC producers, which have oil price objectives much more complicated than simply producing efficiently and delivering returns to shareholders.

During the 1980s, Saudi Arabia fought for oil market share by massively boosting production, crashing prices, but all the while being able to increase volumes enough that revenues compensated for lost income. To implement the same volume-based revenue generation strategy that fed its budget in the early to mid-1980s, today's Saudi Arabia would need to boost exports from the 6.9 million b/d it shipped in June 2014 (when Brent was more than $100/bbl) to roughly 14 million b/d.

The Saudi Arabia's oil-focused rig count has steadily risen to a 20-year high over the past 3 years, not what one would expect from a country flush in oil, with ample low-cost spare capacity (Fig. 8). Saudi Arabia's rising rig count points to an inability to sustain a combined oil and products export level beyond what it ships today.

Short-, long-term response

Oil prices could still move lower in the next 2-3 months due to high crude inventories and continued strong US production, as well as key OPEC producers' refusal to curtail output levels to help rebalance the global market. The factors described in this article, however, are setting the stage for a strong crude oil price recovery. It is likely that Brent crude will trade between $75-85/bbl within a year.

In the medium term (12-24 months), global crude prices will likely remain volatile. US shale drillers respond to price more rapidly than traditional oil producers. Price increases into the $65/bbl range will draw them back into the market, induce them to complete deferred wells, and put downward pressure on prices. Once prices fall sufficiently to drive the marginal drillers out of the market, prices will rise, restarting this cycle.

Volatility discourages longer-term investments in new oil sources outside North America (such as deepwater and larger conventional fields in places like China, Russia, and Latin America). The world now consumes 33 billion bbl/year of crude oil and liquids. The US shale sector, while a global market mover, cannot single-handedly maintain global crude supplies. Herein lies the setup for higher oil prices down the road.

References

1. "Texas Barnett Shale: Total Natural Gas Production 2000 through 2014," Texas Railroad Commission, Production data query system accessed Mar. 6, 2015, (www.rrc.state.tx.us).

2. "Weekly US Field Production of Crude Oil," US Energy Information Agency, Accessed on Mar. 1, 2015, (www.eia.gov).

3. "EOG Resources Reports Fourth Quarter and Full Year 2014 Results and Announces Return-Driven Capital Program for 2015," EOG Resources, Press release, Feb. 18, 2015.; see also, Kemp, J., "Shale producers postpone oil well completions," Reuters, Feb. 20, 2015.

4. "Successful Completion Optimization of the Eagle Ford Shale Presentation," Pioneer Natural Resources, Press release, Nov. 12, 2014.

5. "Large Scale Growth Story with Low Cost and Low Risk," Range Resources, presented at Simmons & Co. Energy Conference, Las Vegas, Nev., Mar. 4-6, 2015.

6. "Investor presentation," RSP Permian, Houston, Nov. 12, 2014.

7. "Corporate Update-February 2015," Cimarex Energy, conference call, Feb. 18, 2015.

8. "February 2015 Investor Presentation," Diamondback Energy Inc., webcast, Feb. 18, 2015.

9. "4Q2014 Earnings," Concho Resources, conference call, Feb. 26, 2015.

10. "Investor presentation," EOG Resources, conference call, Feb. 18, 2015.

The Author
Gabe Collins ([email protected]) is a commodity analyst and an associate with Baker Hostetler LLP, Houston. He earned his BA from Princeton University, New Jersey, and his JD from the University of Michigan Law School, Ann Arbor, Mich.

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