With oil prices straddling the $100/bbl threshold and billions in investment money available for the taking, it was all too easy.
From 2010 to 2015, U.S. unconventional resource developers drilled more than 60,000 wells, adding an incredible four million bbls/d of new production.
Then OPEC turned on the taps and flooded the market with oil. Prices began a downward spiral, sinking to $26/bbl in the first quarter of 2016. Many U.S. unconventional resource developers, burdened with high costs and high debt, began looking for an exit.
“Cut costs, borrow money or liquidate,” Ali al-Naimi, then Saudi Arabia’s minister of petroleum and mineral resources, told U.S. oil executives during a visit to Houston last March, when prices reached their nadir. He added that his country and other OPEC members had no intention of curtailing production to support oil prices.
U.S. shale and tight oil producers were already ahead of Naimi when it came to cutting costs. Through a combination of high-grading the best drilling prospects, productivity improvements through better technologies and lower service costs, supply costs were hammered down. From 2013 to 2016, wellhead break-even prices declined by 55 per cent on average, from $80/bbl to $35/bbl, according analysts at Rystad Energy.
Those that could raise capital did. Equity financings rose from a low of $500 million in the final quarter of 2015 to reach almost $9 billion in the third quarter of 2016.
Others simply exited the market: mergers and acquisitions doubled in 2016, reaching $69 billion as debt-ridden companies sold assets or their entire business to more financially stable competitors.
And then, less than a year after Naimi gave his warning, the Saudis and OPEC relented. A 1.1-million-bbl/d supply cut was agreed upon, buoying oil prices into the $50 range in early 2017.
With lower supply costs and higher prices, U.S. tight oil producers are back in the game with daylight to grow.
International energy consulting and intelligence firm Wood Mackenzie expects companies focused on shale oil and gas plays in the U.S. will increase capital upstream spending by 60 per cent, and production will increase by 800,000 boe/d in 2017.
“In the U.S., the Permian-based producers lead the charge,” says Roy Martin, a corporate research analyst at Wood Mackenzie.
The forecast, based on an analysis of 2017 spending guidance issued during the fourth quarter reporting period, looks at 40 U.S.-focused producers, which Wood Mackenzie tracks on an ongoing basis.
The tight oil and gas–focused U.S. producers spent US$15 billion on capital expenditures in 2016, but Wood Mackenzie sees that rising to $24.5 billion this year. “That’s much higher than we had expected,” Martin says, adding that the analysts had been anticipating a 15–20 per cent rise in spending.
Much of this spending is being driven by supermajors like ExxonMobil, Chevron and Shell, which plan to spend a combined $10 billion in U.S. unconventional plays in 2017.
Longer term, the forecasts get even more optimistic. In its Annual Energy Outlook 2017, the U.S. Energy Information Administration forecasts U.S. tight oil production to climb to six million bbls/d by 2025 and level out at the range outward to 2040. Other forecasts are even more bullish, with one industry forecast claiming the Permian alone will be producing five million bbls/d by 2025.
But there remains a lot of uncertainty about whether operators will be able to maintain competitive supply costs as activity heats up and whether the supply in the ground will translate into long-term production growth above it.
Are supply-cost cuts sustainable?
There is little question the huge decline in supply costs across U.S. tight oil plays has been an impressive feat, but the questions now are, where did those savings come from, and are they sustainable in the long term?
Rystad has attempted to answer these questions through a detailed analysis conducted throughout 2016 of the top tight oil and shale plays. It breaks down supply-cost savings as due to structural changes resulting from productivity improvements and cyclical changes resulting from cuts to service and supply pricing.
The analysis shows significant improvements in drilling, completion and well placement, resulting in better production performance and ultimately economic performance.
As newer high-performance rigs have replaced old ones and the use of pad drilling has increased as operators moved from exploration to development, drilling speeds have rapidly increased in the last two years, reports Rystad. Rigs in the largest tight oil plays are now averaging nearly 800 feet per day compared to less than 600 feet per day just two years ago.
Operators are drilling longer laterals and increasing fracture stimulation intensity across plays, opening up more rock to production and adding recoverable reserves, thus lowering supply costs per barrel. And they are high-grading drilling targets to the best acreage, further increasing recoverable reserves.
While these productivity gains have been impressive, Rystad calculates they only account for around 13 per cent of the 45 per cent decline in total supply costs since 2014. Cuts in service prices account for around 30 per cent of the decline, and Rystad believes these gains will be lost as activity heats up.
Operators, however, are optimistic continued productivity improvements and tighter cost management will mitigate service cost increases, at least in the short term.
Unconventional resource pioneer EOG Resources has undertaken a number of initiatives to keep supply costs in check across its unconventional holdings. The company has permanently high-graded its drilling inventory to focus only on what the company calls premium wells.
“Going forward, EOG’s capital will be focused on wells that are profitable at $40, meaning with modest increases to oil price, our returns have the potential to soar,” says Bill Thomas, EOG’s chief executive officer.
EOG’s focus on cost control and operational efficiencies delivered big time in 2016, says Gary Thomas, the company’s president and chief operating officer. The company had originally planned to spend $2.5 billion drilling 200 wells and completing 270 wells in 2016, but by year-end had drilled 280 wells and completed 445 wells for a cost of $2.7 billion.
“That’s a 40 per cent and 65 per cent increase in drilling and completing activity with only an eight per cent increase in capital,” says Gary Thomas.
While EOG expects pressure on service prices to increase in 2017 as activity increases, it believes it can further bend the cost curve downward.
“Our average daily rig rates are down 25 per cent compared to last year. Fourteen of our drilling rigs, or 60 per cent of the total, are under long-term contracts, and nine of these rigs are at bottom-of-market rates,” he says. “We’ve locked in three-quarters of our casing needs at prices 30 per cent below our 2016 costs.”
EOG is also expecting to keep tight control of completion costs in 2017.
“To further control cost, we’ve also locked in 50 per cent of our frac fleets. And we have diverse sources of frac sand, and our aggregate sand costs are expected to decrease by 18 per cent year-over-year,” says Gary Thomas. “Our expanded water infrastructure systems are expected to reduce our well cost by another $100,000 per well, and because of the combination of operational efficiencies, we expect to complete 15 per cent more wells per frac fleet this year.”
Encana is also looking to lock in its supply-cost savings on its Permian Basin acreage in 2017, says Mike McAllister, executive vice-president and chief operating officer.
The company ramped up its 2017 drilling activity before the end of 2016 to take advantage of lower service costs. And the company remains focused on structural savings on drilling and completions.
“We continue to capture additional operating efficiencies with spud-to-rig-release times dropping below 10 days with our best being below nine days,” he says. “We’ve also improved the efficiency of our completion operations. We have pushed our pumping times up to 20 hours per day…. This compares to more typical efficiencies of 12 hours to 15 hours per day. By making this improvement, we are creating value by lowering our completion costs and getting our wells on production faster.”
Encana is focused on building out its pad-drilling program to cut costs. Last summer it brought on 14 wells from a pad in Midland County, Texas.
“We have now returned to this pad,” says McAllister. “While those first 14 wells continue to produce, we are drilling an additional 19 wells. This will bring us to 33 wells from a single location. This is the largest multiple pad in the Permian to date. Above ground, this means improving drilling and completion efficiencies and increased utilization of existing facilities. Below ground, it’s the first full-scale high-density development in the basin. These 33 wells are across multiple stack zones.”
Aside from focusing on technology, Encana is leveraging its internal expertise to keep supply-cost savings as activity ramps up.
“In addition, our approach to innovation and supply chain management gives us a real advantage in offsetting service cost inflation,” says McAllister. “We control 75 per cent of our capital spending through our centralized supply chain team. This small team is embedded in our operations organization and is staffed with expert professionals who have the commercial skills to understand markets and how to best procure goods and services. This means our drilling completions teams can focus on what they do best—drilling and completing wells.
“We also manage the supply chain by self-sourcing the key consumables in our drilling and completions operations, like sand, water, chemicals, casing and drilling mud. This gives us better pricing and improves our security of supply for those consumables.”
McAllister says Encana has worked to identify “pinch points” for specific services in specific plays and plans ahead to avoid cost inflation. The company saw completions activity picking up in the Permian and responded by locking in a frac spread for 2017 with the option to lock in a second spread.
“We also have a pricing agreement for API sand that we negotiated in 2015 that extends out to 2020,” he says. “With that agreement, and by driving efficiency in our logistics, we expect our all-in sand cost to go down this year. We’ve also had success with non-API or brown sand, which has the opportunity to further reduce our sand costs.”
Encana is also looking at water management to cut costs.
“We’re having success reducing our amount of consumables in our operations,” says McAllister. “As an example, in the Permian, we’re also increasing the amount of produced water that we reuse in our frac jobs from 25 per cent up to 40 per cent. By recycling produced water, we’re also saving on operating costs because we don’t have to pay to dispose of the water. Our approach to sourcing our own water, transporting it by pipe and recycling our produced water in our frac jobs is saving us approximately $1/bbl in the Permian.”
While the large independent producers who pioneered the shale tight oil plays work to maintain their supply-cost gains, global supermajors like Chevron and ExxonMobil have invested heavily in tight oil acreage and are now working their way down the cost curve as well.
“In 2016, we delivered a 30 per cent reduction in our actual operated unit development and production costs and are competitive with our actual non-operated joint-venture partner costs and with some of the best operators in the basin,” says Jay Johnson, Chevron’s executive vice-president of upstream, commenting on Chevron’s more than two million acres in the Permian Basin. “With respect to recovery, we are increasing lateral lengths and continue to evolve our basis of design. Our Permian recoveries per foot have grown between 30 per cent and 40 per cent since 2015 and are expected to increase another 30–50 per cent in 2017. So we are competitive on costs, we are competitive on recoveries, and we are getting better every day.”
Chevron is leveraging a number of its advantages as a multinational company to help manage its supply costs.
“With advanced planning and our ability to leverage our global scale, we’ve secured the crews and materials necessary to execute our program,” says Johnson. “We source tubulars directly from a global supplier that maintains inventories and provides the pipe at global sourced prices.”
“Our rigs have staggered contract durations and competitive rates, and we secured key services with a variety of indexed or performance-based contracts,” he adds.
Chevron is also looking downstream to limit costs and add value to its production.
“We took advantage of the recent market downturn to secure pipeline capacity as well as [natural gas liquid–] and gas-processing and off-take at desirable rates,” Johnson explains. “We have access to multiple market centres to capture the highest realizations, and we’ve contracted capacity with options for expansion to support the majority of planned levels of production through the end of this decade.”
ExxonMobil entered the U.S. shale market with its $39-billion takeover of XTO Energy in 2010. Since then, it has continued to build acreage, most recently through a $6-billion acquisition of 227,000 acres in the Permian Basin. Darren Woods, ExxonMobil’s new chief executive officer, points to the Permian as an example of his company’s progress in driving down supply costs.
“Total unit development costs have been reduced 72 per cent in the last two years to less than $8 per oil-equivalent barrel. We have successfully reduced cash-field expenses by nearly 50 per cent since 2014 to approximately $5/bbl,” says Woods.
ExxonMobil is now leveraging this success and applying it across its unconventional fields.
“We’ve dedicated a team to research and develop techniques to maximize lateral lengths, support next generation well completions and optimize the development of unconventional fields,” he explains. “These combined efforts will improve recovery and reduce the total number of wells needed. While this data is specific to the Permian, we have achieved similar results in other unconventional areas by quickly transferring what we’ve learned and fully leveraging our experience.”
Jack Williams, ExxonMobil’s senior vice-president, says the integrated company brings more to the table than just expertise in developing its shale resource.
“We have that full value chain that goes from the acreage position all the way through to the market. So when you add on the development planning piece, the leveraging, the scale of our company, the research, the midstream, the refining infrastructure on top of our operating prowess and the acreage position, then I think you really have a winning combination,” he says.
Operators predicting huge production growth going forward
With supply costs now globally competitive, operators are predicting huge production growth across tight oil basins in the next decade.
Woods says ExxonMobil has nearly 5,500 drilling locations in the Permian and Bakken plays that are economic at $40/bbl to build on current production of approximately 230,000 boe/d.
“Through 2025, our total net production for these basins could grow to more than 750,000 oil-equivalent barrels per day, representing a 20 per cent compounded annual growth rate,” he says. “Pace will be driven by leasehold facility development, learning curve benefits and technology application.”
Chevron’s Johnson sees similar potential on its Permian acreage.
“Our current production forecast through 2020 is between 325,000 and 450,000 bbls/d, representing a compounded annual growth rate of 20–35 per cent,” he says. “We’re also evaluating cases where we continue to add rigs beyond 2018 and have several scenarios that would grow production of more than 700,000 boe/d within the next 10 years.”
If that sounds optimistic, consider Permian producer Pioneer Natural Resources’ vision for the next decade. Pioneer, currently producing around 235,000 boe/d, has set a target of one million boe/d by 2026.
An internal Pioneer forecast for the entire Permian Basin predicts liquids production could reach five million bbls/d, the equivalent of Canada’s current total production, in 2026. Associated gas production could reach 16 bcf/d, surpassing Canadian production.
But getting there won’t be easy.
With first-year decline rates on individual wells as high as 75 per cent, around 7,000 wells need to be drilled and completed each year just to maintain current production.
There is no shortage of potential targets, as analysts estimate there are 300,000 locations remaining in U.S shale plays. BTU Analytics estimates there are around 50,000 wells with break-evens below $40/bbl, and close to 100,000 wells with break-evens at $50/bbl or less. But those will rise if supply costs do.
ExxonMobil’s Williams believes the U.S. is well situated to manage these costs.
You have this unique environment in the U.S. with private mineral rights and the huge infrastructure we have and the service companies and the capital markets,” he explains. “And all that comes together to really underpin a lot of the development in the U.S. You don’t find those, all that combination of characteristics, elsewhere.”
