The State of Shale
In the brief history of the North American shale energy industry, there have already been both boom and bust years, but today, in early 2017, the shale world is on the precipice of an entirely new era—one not clearly linked to any period of the past. After buzzword talking points focused on low-price-environments or breakeven costs dominated discussions on the health and stability of unconventional drillers and frackers for the past two-plus years, a new storyline is emerging. The industry is not booming in the way it once did when drilling rig numbers were double what they are today. The industry is not, however, caught in stagnancy or suffering in a downturn. Technological gains, industry know-how and the evolution of world oil markets have evolved quickly. In 2017, the state of shale appears to be approaching significant activity level ramp-ups that could redefine the way the industry is described, how it thrives or even survives in the years to come.
Paying To Play Is Paying Off
From 2015-’16, merger and acquisition activities for shale acreage or assets skyrocketed by 117 percent compared to the previous year. Efforts by operators, drillers and service companies during the downturn (2014-’16) paved the way for the massive shift in investment, according to Brian Lidsky, managing director at PLS Inc., a Houston-based information and transaction advisory firm. The industry focused on three areas, Lidsky says, including: decreasing operational costs, increasing recoveries and practicing capital discipline or spending only based on incoming cashflow. Rig counts have risen across most major plays since mid-2016, including the Bakken, Permian, Eagle Ford and Marcellus, thanks in large part to those efforts and a leveled-off oil price.
Those efforts to focus on operations, efficiencies and spending habits have greatly altered the price of oil at which E&Ps need to make a 10-percent-plus return on the investment required to retrieve a barrel of oil from West Texas to Western North Dakota. For comparison’s sake, many oil analysts believe $60 oil is the new $100 oil. Andrew Dittmar, an upstream analyst at PLS, said M&A activity and general drilling and completion activity in several shale plays looks bright this year because of the real ramifications linked to the efforts of E&Ps to change in the downturn.
No shale region has seen more investment or rebound in activity than the Delaware Basin located in West Texas and Eastern New Mexico. The $18 billion in new equity that was invested in the sub-play of the greater Permian Basin earned it “the play of the year” moniker from Dittmar’s team. Newspapers from the Odessa and Midland, Texas, regions have run headlines with the term Permania (the Delaware Basin resides on the western edge of the greater Permian Basin). “People knew there was a lot of oil in place there,” he says, noting that it took experts longer to crack the geologic and technological code for economically retrieving the oil there. “In 2016, it looks like they cracked the code.”
In one year’s time, acreage costs increased from $10,000/acre to $30,000/acre in the Permian. Daniel Fine, a noted oil and gas expert who has worked for multiple New Mexico research institutions and the New Mexico governor’s budget office, says an oil and gas auction in Roswell, New Mexico, three months ago included land deals in the $50,000/acre range. “Everybody is excited and optimistic there [in the Delaware Basin],” he says. “The outlook is good. Even at $40 oil, the rate of return would still be above 10 percent.”
Private equity investors might currently be funneling capital and equity into the Delaware Basin because of a new operational model created by large oil producers during the downturn, but Dittmar expects activity to spread. In both the Bakken and Eagle Ford, deal activity climbed in 2016. “We expect those plays to be big winners when we come into 2017,” he said. “As confidence builds in oil prices that we are going to be above $50/b, we are going to see more interest in those oil plays. There will be less to buy in the Delaware.”
Investors have already regained their confidence in shale, says Stephen Berman, senior equity research manager at Canaccord Genuity. After two years of market fluctuations created by OPEC production actions, Berman believes both OPEC and investors understand why shale is a long-term venture even after two-years in a downturn. “OPEC realized after two years they weren’t going to put U.S. shale as an industry out of business,” he says. “Now, we compete very effectively in a $50/b oil world. I think OPEC and the rest of the world see that the U.S. shale industry is here to stay and I think investors realize that now too.”
Mangesh Hirve, chief operating officer for global oil and gas research firm 1Derrick, believes it’s not only U.S. investors who are back onboard with U.S. shale. Investors in Europe and Asia are eyeing positions in the U.S., currently with a focus on the Permian. Some have taken creeping positions as they wait to pounce on attractive acreage or companies. Early investors have already made good money, he says. According to Hirve, international investors want to see oil plays at the discovery or near production stage that they can enter and quickly experience production or production gains. European and Asian investors don’t want long-cycle projects, he says. Many pay in cash and want to diversify their portfolios. In the Permian, he says, “you can start production and in two months’ time the money hits your bank.”
The New Reality of Production
Trish Curtis, president of oil and gas research and economic analysis firm PetroNerds LLC, knows why investors and E&Ps are ramping up activity plans at $50/b oil. Curtis has performed extensive research on the shale energy production industry, traveling from London to Saudi Arabia to North Dakota to speak on her research. For the Oxford Institute for Energy Studies, she outlined why cheerful and hopeful talk from many operators in 2015 and 2016 was not merely fluff. In her research paper, “Unravelling the US Shale Productivity Gains,” Curtis was able to dissect and highlight just how far operators have come the past three years on the production front. “You know companies are very bullish about their own operations,” Curtis says. “You can’t just believe them, though. You have to actually look at what they are doing.”
“When you started looking at production figures for several companies, individual well production was looking good. You could see a pretty distinct change,” Curtis says. “What was impressive is that you weren’t just seeing it in one spot. You were seeing it with all kinds of companies in all types of basins.”
During the downturn, the forced requirement by operators to spend within cashflow and the need to produce more with less helped the industry change course. According to Curtis, not everyone totally grasps the level of change that has occurred or the long-term impact it could have on activity levels in the industry and the global oil supply picture. The well productivity gains achieved in the downturn have been outstanding, Curtis says, pointing to well production type curves in nearly every basin that reveal wells drilled and put onto production today will produce more during initial production periods and decline less over time than previously drilled wells fracked in the same areas.
“I think a lot of folks did not realize how these new wells were actually performing. I think people sort of discounted that and thought operators were just highgrading or putting more sand down the well. But, when you look at the decline curves, it is clear the gains are real,” Curtis says.
The implications from the gains are also real, and not yet fully understood, she adds. People don’t truly understand what the productivity gains mean yet because they happened so fast at a time when the focus was on depressed oil prices and OPEC actions. “You can’t really unlearn this stuff. The fact that they are getting more oil out of these wells is very impressive,” she says. “That has very significant and long-term ramifications for U.S. production.”
Curtis is specifically impressed with new completion designs and strategies used in the past two years. Operators today are attempting to keep fractures closer to the well bore to drain the surrounding reservoir more efficiently. With fractures closer to the well bore, more well bores can be drilled without fear of a nearby well bore’s fracture network bleeding into a neighboring well. More drillable locations (that don’t impact production for a neighboring well) means the recovery factor of a field increases.
Production Gains Have Chance To Shine
With oil prices steady at or above the $50/b mark, private equity backing and a new leaner and meaner approach to operational efficiency, producers and their bullish talk will now be put to the test in 2017 and beyond. Already, capital spending and budget plans are distinctly up from the previous year. Kenneth Medlock, senior director for the Center of Energy Studies at the Baker Institute of Public Policy at Rice University, spoke with completion engineers, drilling contractors and analysts to reveal the true ability of shale producers to scale-up activity in 2017. “The recent increase in oil prices on the heels of OPEC’s agreement for production cuts stimulated a lot of commentary on how rapidly U.S. shale producers would respond,” Medlock says. “We have been tracking the changes in costs for upstream activity in the U.S. and have noted both productivity changes as well as renegotiations with upstream service providers,” adding that “disentangling the two issues is fundamental to understanding how domestic production will respond.”
Medlock’s team examined which challenges producers will face during ramp-up efforts that will come in two phases: completing previously drilled but uncompleted wells and drilling new wells. Revamped activity levels could put a crunch on service company equipment and manpower availability, which in return could increase—if it hasn’t already—the price operators pay for pressure pumping and other well-related services. An increase in prices may impact breakeven prices, driving them higher and reducing operators’ chances at reaching acceptable rates of return at oil in the $50 to $60 range.
Production gains achieved during the downturn could offset the service cost increases expected with higher oil prices, but to what extent Medlock’s team is uncertain. From 2014 to 2016, the dollar-per-barrel cost declined by 63 percent and the dollar-per-well cost declined by 34 percent. This indicates the production per well increased during that two-year span, and, of the per-barrel cost reductions that took place in 2014-’16, 69 percent came from productivity gains and 31 percent came from service cost reductions. If productivity gains do not persist at the same time service-costs rise, Medlock’s team questions how breakeven pricing will look at current oil strip prices. “The degree to which productivity persists is a critical element in understanding the responsiveness of shale to price increases,” the team said in its report.
Operators in the Bakken, Permian, Eagle Ford and Marcellus shale have offered a clear indication that production, and any gains made in the past two years will be tested this year. Both the messages to investors and contracts signed with service companies and rig providers show 2017 will be a massive departure from the 2014 to 2016 downturn. Rig counts are up and rising in most plays, sand providers are counting on revenue growth from contracts or conversations already had with operators and, as Medlock says, what hasn’t killed existing shale players has made them stronger. “Those who have weathered the last couple of years will take no solace in this, but many firms in the industry had built up a good bit of internal redundancy as things ramped up through 2014,” he says. “To the extent that this redundancy was unnecessary, going through a downturn will force firms to rationalize all of their costs. So, as they shale industry emerges into 2017, it is in many ways reflective of survival of the fittest.”
**Side Bar 1**
Pressure Pumper Activity
Some energy service companies are tweaking customer retention strategies; others are buying up used horsepower.
Rethinking market share – Halliburton achieved a company-level record market share in 2014-’16. In recent months, the global energy services firm has ceded some of that share for strategic purposes. Instead of contracting to firms looking for lower service fees, Halliburton is keeping equipment available for customers looking to ramp-up at higher costs.
Confident with the FRAC symbol – After acquiring the North American assets of Trican, Houston-based energy service firm Keane Group has gone public on the New York Stock Exchange using the ticker symbol FRAC. With the purchase of Trican’s assets in 2016, Keane now has 950,000 horsepower available for pressure pumping. In mid-2016, Liberty Oilfield Services acquired the North American assets of Canadian-based pressure pumper Sanjel Corp.
The right time to buy – Basic Energy Services and Mammoth Energy Services have purchased additional pressure pumping horsepower and additional fracking equipment. Basic purchased 74,000 hp and additional equipment for $28.5 million—or just under $400/hp. Mammoth chose to buy new and purchased 57,500 hp and associated equipment for under $500/hp. Mammoth said buying new was a better option to meet the requirements and performance standards it has. Basic was content with its equipment—built between 2013 and 2014—and will add software upgrades to all pumps to fit Basic’s sophisticated processes.
The Mood On Sand
Two of the biggest frack sand suppliers to the North American shale industry are experiencing the effects of improved market activity rates and a broad industry push to pump more sand downhole than it did three years ago. Wells completed in most U.S. shale plays today versus three years ago pump roughly three to 10 times as much sand downhole. Hi-Crush Partners LP said that, beginning in January, the Houston-based sand supplier with four mines spread throughout Wisconsin, has been sold out of every grain and every grade of frack sand it sells. “It is undeniable that we are seeing a substantial increase in demand for our products and services even though we are only in the early stages of a market recovery,” Robert Rasmus, CEO of Hi-Crush said.
Gary Kolstad, CEO of Carbo Ceramics, is also optimistic about the prospects for 2017. Revenue projections for 2017 appear on track for a 40 percent to 50 percent increase compared to the previous year. Like Hi-Crush, the Carbo team believes industry will continue to contract for sand over the more expensive engineered ceramic proppant. “The current commodity price environment continues to lead E&P operators to generally focus on the lowest upfront completion cost,” Kolstad said. In addition to its oil and gas sand and ceramic supply business, Carbo will continue consulting for fracture stimulation jobs this year. Other industries will garner some outreach from Carbo as well.
Early-year capital spending plans by many operators targeting a North American shale play are up from 2015 and 2016 budgets. The trend among most is an increase in capital for drilling rigs and completing drilled but uncompleted wells. Some E&Ps are even setting aside capital for future land purchases, midstream build-out projects or other activities. The following is a brief snapshot of operator plans for 2017, all of which have increased numbers for their respective rig programs, well completion plans and capital budgets from the previous year.
Rig program: 2 Williston Basin; 5 Permian; 1 San Juan
Completion/Well Plans: Bakken (42); Wolfcamp (100)
Capital plans: $260 million Williston Basin; $510 million Permian; $170 million San Juan
Of Note: WPX Energy used the release of a multi-year growth plan to its advantage in forming service contracts before it incurred service prices increases. Through 2017, roughly 70 percent of all contracts for drilling and completions have been locked in.
Rig Program: 5 Permian Basin; 2 Eagle Ford; 1 Montney
Completion/Well Plans: Permian Basin (145); Eagle Ford; Montney
Capital Plans: $800 million Permian Basin; $250 million Eagle Ford; $460 Montney
Of Note: Using intel and completion know-how from one basin, Encana has found a way to effectively implement completion and production changes into a different basin in less than 12 weeks to enhance completion designs and overall production across multiple basins.
Cimarex Energy Co
Rig Program: 8 Permian Basin; 10 Mid-Continent
Completion/Well Plans: Wolfcamp; Meramec
Capital Plans: $1.2 billion total, with 66 percent headed toward Texas operations.
Of Note: The possibility of rising services costs may require Cimarex to pump less sand downhole per well, but that scenario does not bother the Cimarex team. The company does not focus on pounds of sands per foot, but instead analyzes how effective sand is pumped and placed per frack cluster—or entry point—into the horizontal well bore.
Whiting Petroleum Corp
Rig Program: 5 Williston Basin; 1 DJ Basin
Completion/Well Plans: Bakken, Three Forks; Niobrara
Capital Plans: $580 million Williston Basin; $420 million DJ Basin
Of Note: Well productivity gains experienced by Whiting in the Williston Basin are not related to geology, the company said. Production increases—which are spread out across Whiting’s entire basin position—are now the norm.
Rig Program: 10 SCOOP/STACK; 6 Eagle Ford; 6 Williston Basin
Completion/Well Plan: SCOOP/STACK (100); Eagle Ford (170); Bakken (75)
Capital Plans: $660 million SCOOP/STACK; $660 million Eagle Ford; $660 million Williston Basin
Of Note: Marathon is shifting its focus to U.S. onshore opportunities where it believes it can grow production by 20 percent from Q4 2016 to Q4 2017.
Anadarko Petroleum Corp
Rig Program: 14 Permian Basin; 6 DJ Basin
Completion/Well Plans: Delaware, DJ Basin
Capital Plans: $820 million Delaware Basin; $840 million DJ Basin
Of Note: Oil production in the company’s Delaware Basin position will increase by roughly 80 percent year over year. Al Walker, CEO of APC, called the company’s Permian/Delaware asset “easily the most exciting.”
Antero Resources Corp
Rig Program: 7 Marcellus/Utica
Completion/Well Plans: Marcellus/Utica (170-with another 30 DUCs)
Capital Plans: $1.3 billion Marcellus/Utica
Of Note: With five completion crews contracted this year already, Antero expects more may be needed. And In 2018, the number of frack crews needed should double.
Continental Resources Corp
Rig Program: 5 Williston Basin; 11 SCOOP/STACK
Completion/Well Plans: 131 gross Bakken DUCs; 17 new Bakken wells; 132 new SCOOP/STACK wells
Capital Plans: $1.9 billion Bakken, SCOOP/STACK
Of Note: For the investment into completing DUCS, Continental believes it will receive a 100 percent rate of return. This year, Continental intends to invest $230 million into land acquisitions, facilities or other activities.
Author: Luke Geiver
Editor, North American Shale magazine
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