Jeff Balmer, Encana’s vice-president in charge of the Eagle Ford operations, is tasked with improving productivity and driving down costs in the Texas shale formation.Darren Abate/The Globe and Mail
Working on the towering, steel-blue rig under a late winter sun, the drill crew on contract with Calgary-based Encana Corp. is replacing a downhole drill motor before sending a 25-kilogram bit boring along a curved course that will flatten out and run horizontally – under the hooves of the cattle grazing nearby – through a thick seam of oil-bearing shale.
A separate crew will then shoot chemically laced water under high pressure into the ground to fracture the rock in order to coax light, sweet crude from the Eagle Ford shale formation, one of the most productive oil fields the United States has ever seen.
The Dromgoole well, situated in the hard-scrabble ranch land of south Texas, is at the epicentre of a boom that has brought vast riches to a traditionally poor region of the oil and gas producing state.
From virtually no production five years ago, the Eagle Ford now pumps out 1.7 million barrels a day – a stunning growth record propelled by years of high crude prices and advances in technologies such as horizontal drilling and hydraulic fracturing. By comparison, Alberta's oil sands sector produces just over two million barrels a day.
Along with the Permian shale play in West Texas and North Dakota's Bakken region, the Eagle Ford's booming production is behind the oil renaissance in the U.S. that has contributed to a glutted global market.
But its future is now in doubt as Saudi Arabia fights a price war over global market shares aimed at crippling high-cost producers in America's shale fields and Canada's oil sands.
As the world watches, Karnes City and other south Texas towns are starting to feel the effects of the oil supply surge.
Companies are idling rigs and laying off staff, meaning fewer crews to pack the local motels and restaurants. Karnes City has been spending money to upgrade sewers, improve its schools and expand its jails to handle the boom – but now residents worry about the population melting away.
Charlie Malik's NAPA auto parts business is located on the town's three-block-long main drag, and has grown fourfold since the oil companies came to town, forcing him to expand into the building next door.
"People don't realize what this poor, broke-ass county was like before," says Mr. Malik, whose father started the business 50 years ago. "People struggled; kids knew when they got out of high school, they were leaving. ... Since this happened, the difference is day and night."
But he knows the bloom is fading. "I'm hoping things get to a more sensible pace, but I don't see them stopping altogether," he said.
Texas producers are starting to stumble in the the shale oil industry equivalent of the Red Queen's Race – the Alice Through the Looking Glass scenario in which one must run faster just to stay in the same place. The dramatic reduction in drilling and hydraulic fracturing is reducing the number of new wells coming on stream. Output from shale oil wells declines rapidly after an initial burst of strong production. As a result, the industry is quickly reaching the point at which its newly completed wells will not offset the steep decline rates of the existing ones.
It's the scenario the Saudis – and hard-pressed producers worldwide – hoped would play out.
The U.S. shale sector is a prime target – both because of its soaring output over the past four years and because production there is expected to be hit most rapidly by slumping prices. However, even those producers can't shift gears quickly enough to keep the industry's pain from deepening. Opinions differ on precisely when U.S. crude production will begin to fall. It's clear that, for the U.S., this cycle's "peak oil" is just around the corner, if not upon us.
"When it does turn, it's not going to be a silver bullet because there'll still be a lot of surplus oil," says Karr Ingham, an Amarillo-based economist who works with an alliance of independent companies in the state. "This is going to be a long process and we're still very early in the process."
Rig counts plummet
The number of rigs working in the U.S. fell again this week, according to figures released Friday by Houston-based services company, Baker Hughes Inc. Over all, the U.S. lost another 67 oil rigs, and is now down 38 per cent from a year ago. Declines were seen in the Eagle Ford, Permian and Bakken, and Mr. Ingham expects the rig count to be down 70 per cent in Texas by midyear, compared to its 2014 peak.
On Friday, the Paris-based International Energy Agency said declining rig counts have yet to reverse North American supply growth. "U.S. supply so far shows precious little sign of slowing down. Quite to the contrary, it continues to defy expectations," the IEA said in its monthly Oil Market Report, which raised the agency's outlook for North American production.
The IEA report drove crude prices into a deep slump on Friday, with West Texas intermediate (WTI) losing $2.21 – or 4.7 per cent to $44.84 (U.S.) a barrel. After a period of recent calm, the North American benchmark dropped 9.6 per cent this week. North Sea Brent posted a similar loss, down 8.5 per cent this week to $54.67 a barrel.
Despite fears of a growing glut, there are signs of slowing production in key U.S. shale regions. American production continues to grow over all and has topped 9.3 million barrels a day. But North Dakota officials said this week that crude output in the state fell in January, and the U.S. Energy Department expects Eagle Ford output to dip slightly in April. Most analysts expect rising demand and falling American supply to bring the market into better balance by late summer.
But a price recovery will be slow – muted by a number of factors: Nimble shale oil producers are driving down costs in order to produce crude profitably at lower prices; brimming storage tanks are absorbing the current surplus, but the owners of that crude will be looking for a market at the first sign of higher prices; and there is a growing number of wells that have been drilled but not fracked, effectively creating an underground inventory of crude that can be produced with less capital spending than is typically required.
Despite the slump, Encana is doubling down in the shale oil business after spending $10-billion last year on Eagle Ford and Permian assets as it shifted focus from natural gas to liquids. The company recently cut its 2015 capital budget by 25 per cent from levels it had projected in December, but it is going full speed in the Eagle Ford and Permian basins, as well as in Canada's Duvernay and Montney shale plays.
Its strategy will depend on men like Jeff Balmer, the vice-president in charge of Eagle Ford operations, who is tasked with improving productivity and driving down costs in the properties acquired from Freeport-McMoRan Inc. last June. In the nine months since acquiring Eagle Ford assets, Encana has cut drilling times by a quarter and also increased average initial production from its wells by 25 per cent.
"If you look at the improvements on the drilling and completion side, as well as the base production, the progress we've made in the short time we've been around is phenomenal," he said in an interview at the Karnes City field office. The company says it can produce oil profitably from its Eagle Ford and Permian properties at $50 a barrel – although spot prices averaged less than that in the first quarter.
On Encana's Dromgoole site, drilling contractor Helmerich & Payne Inc. is operating a high-efficiency "walking rig," which can be moved along massive tank-like treads across the length of a pad to drill a series of three wells in assembly-line fashion. The Tulsa, Okla.-based contractor says the new rigs can save companies nearly $500,000 per well.
The H&P team first drilled the vertical portions in sequence, and then the horizontals. At a recent visit, it was beginning the production portion of the third well. Once total depth is reached, the crew will case the hole with steel tubing and cement it in. Then the fracking operators will take over to complete the well and stimulate production.
As it forges ahead with its strategy to shift focus off natural gas production, Encana expects to focus its capital spending on the key shale liquids plays. It plans to increase production from its four resource plays to 240,000 barrels of oil equivalent by the end of the year from 183,000 at the end of 2014. In Eagle Ford, it intends to grow from 36,000 barrels of crude and natural gas liquids a day to at least 41,000 and as much as 48,000, but it will reduce the number of rigs there from four to three, and perhaps to two.
Encana is also experimenting with refracking old wells in order to capture more crude without the multimillion-dollar expense of drilling new holes. It has reworked 25 wells, and has 300 more available if the engineering proves cost effective.
"We've found pretty good oil recovery from it," said Tim Baer, an Encana engineer who leads the effort. "Now we have to figure out how to do it more cheaply and efficiently."
The Calgary company is resisting the general trend in Texas as competitors slash operations in order to ride out the storm. By late summer, Mr. Ingham expects the state will see up to 70 per cent of its oil-oriented rig fleet parked, and as many as 50,000 jobs lost. The biggest players in the shale sector – companies like EOG Resources Inc. and Marathon Oil Corp. – are cutting their capital budgets by 30 to 40 per cent.
Oil inventory soars
Marathon – a big player in the Eagle Ford and Bakken – will reduce its overall rig count from 33 at the end of 2014 to 14 by summer. In the Eagle Ford, it will cut from 18 to 10 and reduce the number of wells drilled from 350 last year to 220 in 2015, although it will target 40 per cent of its capital spending in the south Texas play.
Despite those cuts, total production will be 5 to 7 per cent higher in 2015, and output from its three shale plays in Texas, North Dakota and Oklahoma will be 20 per cent higher, Marathon chief executive officer Leo Tillman told analysts in recent call. Meanwhile, it expects to cut costs by $225-million in 2015 by squeezing its service providers.
EOG – the largest operator in the U.S. shale oil fields – is cutting its capital budget 40 per cent this year to $5-billion. EOG is pursuing a strategy that is increasingly used in the industry – drilling wells but waiting until the market improves to frack them and start production. The company has an inventory of 200 uncompleted wells and plans for that number to build through the year.
"We're not interested in growing oil when oil is at the bottom of the cycle, and so we are deferring growth until future years when prices get better," CEO Bill Thomas said in an conference call. (Encana's Mr. Balmer says his company won't employ that tactic, preferring to reap the cash flow from its invested capital as soon as possible rather than wait on some hoped-for upturn.)
North Dakota saw its number of uncompleted wells jump by 75 to 825 in January, as producers are spending the $4-million needed to drill a deep, horizontal well but forgoing the $4-million to $5-million needed to frack it and connect it to the Bakken's gathering system.
"We're just seeing that inventory grow and grow and grow," Lynn Helms, director of the state's Department of Mineral Resources, said on a call this week.
Mr. Helms said producers have a year to complete wells that have been drilled, and he expects more completions and production this summer as demand picks up and some operators hit that regulatory deadline. At the same time, producers could benefit from a sharp decline in state taxes if WTI prices average less than $55.09 a barrel for the next two months, and that tax cut would also encourage production, the state official said.
North Dakota producers are particularly stressed as realized prices for Bakken crude have fallen to $32 a barrel. At those prices, state officials forecast production would drop from current 1.2 million barrels a day to one million in July, 2015, then 875,000 in July, 2016, and 720,000 in 2017. The department estimates that industry currently needs prices of $75 a barrel to sustain production growth.
With crude from the Eagle Ford and Bakken flooding into storage, the U.S. industry is increasingly agitating for an end to the export prohibition that keeps American crude bottled up on the continent. At $100 oil, the export ban was an irritant; now it's crippling, said Ed Longanecker, Austin-based president of the Texas Independent Producers & Royalty Owners Association, which represents most of the oil companies operating in the state.
After shrinking this fall, the gap between Brent and WTI has widened to around $10 a barrel. "At these prices, $10 a barrel makes a big difference for us," Mr. Longanecker said in an interview. "This is a big priority for the United States." This week, a delegation including CEOs from companies like Marathon, ConocoPhillips Co., and Occidental Petroleum Corp. met with White House staff to press for a lifting – or at least an easing – of the ban. But U.S. President Barack Obama has shown little sympathy for their cause.
Amid the gloom, some officials are counselling patience. The industry saw a steep price drop in 2008-09 recession but rebounded smartly. While most observers don't see such a rapid recovery, they do expect a slow-but-steady improvement starting in the second half of this year.
Christi Craddick, the state's top energy regulator, grew up in West Texas's Permian district and knows the cyclical nature of the industry. Oil and gas represents 40 per cent of the state's economy, and producers contributed a $15.7-billion in state and local taxes and royalties last year, a record that may stand for good while.
"We don't know yet" how hard the state will be hit, Ms. Craddick said in an interview at the Texas Railroad Commission, a few blocks from the state legislature in Austin. "But Texas is well positioned to weather the storm specifically because we have infrastructure, because of our consistent good regulatory climate, and our excellent business climate."
She figures the industry would prosper with a WTI price of $65, while $80 would be "great." "Everybody would love to see $100 oil again, but I'm not sure we'll see it." Meanwhile, she said, the lower prices are motivating companies to innovate and reduce their costs.
Service companies feel the pain
The companies that service the oil producers are feeling their pain.
On a Friday afternoon in a suburb of Houston, men and women who deal in steel tubing for oil fields gather for a networking event – a chance to trade war stories, have some drinks, and hit golf balls from a second-floor porch onto a range that scores your accuracy. The talk is about layoffs, plant closings and customers squeezing suppliers until margins disappear.
In a presentation to the group, John Daniel, an analyst with Houston-based Simmons & Co., deepens the gloom. He suggests service companies' cash flow will drop by an average of 40 per cent this year, and there will be consolidations – meaning bankruptcies and acquisitions.
"We believe the carnage within the oil service sector will be significant, but also relatively short lived," he tells them.
Lucas Mezzano didn't need an analyst to deliver that message – he's seeing it in slumping sales and industry layoffs.
Mr. Mezzano sells coiled steel tubing that is used in oil and gas production for Tenaris SA, a Luxembourg-based company with operations across Canada. Tenaris owns the Algoma steel plant in Sault Ste. Marie, Ont., which has recently reduced its production line from three shifts to two. The company also announced it is closing its welded tube mill in Conroe, Tex., with the loss of 230 jobs.
"Everybody is asking for discounts ranging between 15 and 20 per cent," said the Argentine native who spent several years in "The Soo" before moving his family to Houston. "In many cases, that's not possible."
But there is a longer-term danger as the producers download their troubles onto the service sector in a bid to cut costs. As drilling crews drift away from the oil fields of south Texas and North Dakota, there is no guarantee they will return quickly when the industry needs them. As capacity is lost among the steel suppliers and chemical companies whose products are essential to modern production techniques, the rebound will be handicapped by their loss.
And the U.S. ambition to eliminate the need for imports – other than from Canada – will be thwarted.