Expectations of continued USD 100/bbl of oil were shattered by a sharp price drop last year that eventually halved the prices of benchmark crudes. Prices were still sinking at the start of the year to lows not seen since 2009 due to a global oversupply of oil.
The US has gone from the world’s best import market for oil to a market moving producer, and a large and growing exporter of refined products. Total US output rose from 5 million B/D in 2008 to 9.2 million B/D in December, according to the US Energy Information Administration (EIA), which predicts 9.3 million B/D by the end of this year.
While the magnitude of the drop rivals the one in 2009, the cause of it resembles the longer-lasting downturn that began in the 1980s, after a run of high prices rapidly expanded oil supplies, creating a glut.
The rise of oil flowing from US shale formations has sparked a battle for control of the market with OPEC, which has been unwilling to reduce its production to prop up prices because that would further erode its share of a market where production outside OPEC rose by 2 million B/D in 2014, according to the EIA, which said demand was up by 900,000 B/D.
OPEC’s goal is to ultimately reduce production by forcing output reductions by what Saudi Arabian Minister of Petroleum and Mineral Resources Ali al-Naimi has described as “inefficient producers.”
The strategy, which allowed the price of a barrel of oil to drop to less than USD 50 early this year, appears aimed at the independent companies producing millions of barrels a day from tight, unconventional formations, where the cost of extracting oil is far more expensive than Saudi Arabia’s world-class reservoirs.
So far the news suggests this could be a slow-moving process. The large, public US producers have announced significant reductions in planned exploration and production (E&P) budgets, but still predict greater production in the year ahead.
In mid-December, when al-Naimi was asked if OPEC would act to reduce supplies, he said, “As a policy for OPEC—and I convinced OPEC of this … it is not in the interest of OPEC producers to cut their production, whatever the price. Whether it goes down to USD 20, USD 40, USD 50, USD 60, it is irrelevant.”
Around the time that comment was reported from a conference in the Middle East, a story from Bloomberg quoted Harold Hamm, chief executive officer of Continental Resources, as saying that US producers can lower their price of production more than OPEC countries can, and calling the organization a “toothless tiger.”
Both sides have reason for tough talk—many US independents like Continental have staked their future on shale, and OPEC countries see that growth reducing their export income and ability to influence oil prices.
Armed with world-class reservoirs and a deep cash reserve, Saudi Arabia can afford to live on less. The EIA predicts oil at USD 68 would mean a 35% reduction in OPEC oil export revenues, and oil prices have dropped significantly from there. The Saudis face pushback from OPEC members, such as Venezuela, which lack the low-cost production and cash reserves. They have asked for an emergency OPEC meeting to consider production cuts, but Saudi Arabia has blocked any meeting before the next regularly scheduled one in June.
Moves by OPEC to raise prices would reduce the pressure on unconventional producers, who are feeding a boom in US refinery construction, which could further increase exports, reducing demand from refineries around the world for OPEC crude.
And to make matters worse, China, the world’s largest importer, is working to limit its future demand. Wood Mackenzie’s recent global outlook said, “China’s economy is evolving and the nature of its energy demand growth is changing. A more rapid than expected shift to consumption-led growth could slow energy demand.”
For independents, discussions of how long they can hold out in this test of wills commonly comes back to the question: What is the break-even price for US shale producers? The goal is a price where the losses will force them to shut in wells.
So far that question has remained unanswered. Based on statements from US companies and analysts, lower prices will slow the growth of US shale plays and be a severe financial stress test for E&P and oilfield service companies. Aggressive cost reduction moves have already begun, including layoffs, and bankruptcies and forced sales of weaker companies are expected in a business that grew by borrowing hundreds of billions of dollars.
Forcing US producers to significantly cut production could require years of low prices. A study of production from North Dakota’s Bakken formation found that if the price paid to producers there drops to USD 35—about USD 5 below the price paid in the state in early January—production will slow by July to 1.03 million B/D from 1.2 million B/D, according to the North Dakota Department of Mineral Resources. If that price persists until mid-2017, the loss is expected to be less than 500,000 B/D.
“For the last 3 months, I have left every meeting with an international company or US company telling them I wouldn’t make a business decision based on US production being less important from an oil standpoint in the future,” said R.T. Dukes, senior analyst at the energy research firm of Wood Mackenzie.
More for Less
The answer to the widely asked question about the break-even price for US shale production is that it varies widely and is likely to change over time. Those who follow unconventional producers say the cost of producing a barrel of oil from shale differs from play to play, company to company, and well to well. And the number will likely change this year as unconventional producers push hard to cut costs and increase productivity.
“We have seen almost across-the-board cuts” in E&P spending, but companies continue to project growing output,” Dukes said. If they succeed, oil prices at “USD 75 in 2015 might provide the same opportunities at USD 90 in 2014 as companies lower costs and hone in on the best areas.”
While the growth rate will slow, drilling new wells to more than replace rapidly declining output from old ones is going to require aggressive cost reductions.
“Everything we see is operators cutting budgets. Some 20% to 50%, some 60%. The norm is in the 20% to 30% range,” said Christopher Robart, director of Energy Insights at the energy information firm IHS. “At the same time, most operators are currently forecasting single-digit growth in production for 2015.”
In the short run, operators can focus on prime prospects in areas where they have learned how to optimize production. Keeping production rising over the longer haul will ultimately require investment in new areas with higher costs during early development periods.
Low prices are expected to limit future growth in the Canadian oil sands where producers are expected to complete announced expansion projects, increasing the output of the tarlike bitumen to 2.27 million B/D in 2015, up from 1.95 million B/D in 2013, according to the Canadian Association of Petroleum Producers’ 2014 annual forecast.
Oil production in Canada has more than doubled over the past decade and is expected to rise, even with lower oil prices.
The price challenge is magnified because heavy oil sands crude sells at a discount due to higher shipping and refining costs. But that is not likely to shut down current operations, or construction in progress, said Andrew Leach, a professor at the University of Alberta. “With oil sands, existing production is fairly robust. Some have operating and sustaining capital costs under USD 20/bbl. But the new stuff is what’s at risk,” Leach said. “Unlike a shale play, you would not need the same level of reinvestment to keep production constant (in an oil sands project), but you’d need a lot of investment to grow production.”
This could slow oil sands growth because proposed projects cannot meet the profit threshold required for financing a project when prices are down. “I think it’s likely that, unless things get a lot worse, you’ll see most of the projects under construction completed, but I doubt anyone’s going to announce new capacity beyond that,” Leach said.
Shale developments do not carry the enormous up-front costs of an oil sands project, but it takes significant money and time to lease acreage and to figure out how to profitably produce oil in an area.
Until now, bankers and investors have been willing to lend money, often in the form of high-risk debt known as junk bonds, and buy stock to help companies through this period of negative cash flow. The big drop in the value of E&P stocks and bonds suggests that those sources of funding are going to be tough to come by for some time.
The Big If
This year, unconventional producers, such as Continental Resources, will need to prove they can produce considerably more oil for significantly less cost. It added to the pressure to do so by closing out its hedging positions last fall, which had previously locked in higher prices for oil sold, even as the markets declined. The widely publicized move paid it USD 433 million, but exposed Continental to the risk of falling prices.
Reducing the company’s break-even costs will require a combination of lower-operating and materials costs, as well as more productive wells.
For example, Continental released a revised 2015 E&P budget in December, chopping its expected spending to USD 2.7 billion, which is 10% less than it spent last year and far less than its original 2015 budget. It predicted that production would rise from 16% to 20%.
On the cost-reduction side, its budget called for a 15% reduction, lowering the number of drilling rigs running from 50 to 31 as it focuses on its best acreage in the Bakken, and to a lesser extent on newer plays in western Oklahoma. On the production side, the company said it planned to rapidly apply what it has learned from field tests last year that indicated it could increase its estimated ultimate recoveries (EUR) from approximately 600,000 BOE per well to 800,000 BOE.
In its second quarter earnings report last year, Continental said that it had been able to achieve increases on that scale by varying its fracturing fluids with formulas using little or no gel. That approach is a break from what had been common practice in the Bakken. It also reported promising results from using two and three times as much proppant injected using shorter stages. It is also testing whether to add fracturing stages, from 30 to 40 per well, and the ideal spacing for them.
But those projections were made when oil at more than USD 70/bbl was still a fresh memory, and few were predicting it would go down to less than USD 50.
With oil prices so volatile, projections of spending and production from unconventional formations have been in flux. Some producers had not offered E&P spending budgets in December because of the level of price uncertainty while others put out revisions.
Benchmark prices near USD 50/bbl have altered price perceptions. On a day when the West Texas Intermediate price was flirting with USD 55/bbl, Robart said US shale exploration companies would “be ecstatic at USD 70 to USD 80.”
The Bakken Test
Bakken production this year could be a telling indicator. Among the three biggest US shale plays, which also include the Eagle Ford and the Permian Basin in Texas, it is said to be the toughest case.
Break-even prices there are generally considered higher because the formation requires relatively deep wells, which cost more to drill. Also, the price paid has consistently been lower than the benchmark because shipping the oil is more expensive as much of it must be shipped by rail due to limited pipeline capacity.
It is an example of how hard it is to find a break-even price in an enormous play. “People want us to say the Bakken is economic or not,” Dukes said. “It is not great is some areas in the Bakken and really good in others, and the same is true in all the other plays.”
North Dakota drilling rig counts began declining in December, and that is just the start. The rig count in the Williston Basin, which includes the Bakken, “is set to fall rapidly during the first quarter of 2015,” according to the monthly newsletter from Lynn Helms, director of the North Dakota Department of Mineral Resources, which regulates the industry. Break-even levels in 12 areas of North Dakota ranged from USD 29 to USD 77, according to the department. The lowest were reported in three areas clustered in southwestern North Dakota where the break-even ranged from USD 29 to USD 41. (Break-even is defined as a price allowing a 20% internal rate of return).
Drilling fewer wells in formations known for rapid production declines would seem to guarantee a lower output, but in 2009, during the last oil price swoon, that did not happen. Back then, the Baker Hughes rig count in North Dakota sunk from 89 rigs in November 2008 to an average of 35 in May 2009. While Bakken production slipped early in 2009, by December it was up 45% from the same month in 2008.
That showed how companies can improve young technologies. But back then, prices and the rig count were recovering by year’s end, which may not be the case this time around. Also this time, far more barrels a day need to be added to sustain more than 1 million B/D of production.
Difficult Conversations
A sharp drop in prices and the number of rigs working should speed the transition to new rigs able to drill wells faster, and allow operators to choose from the best remaining workers. Companies will focus on well-known areas where they have learned how to produce most efficiently and have paid for the infrastructure to do so. Customers have already begun squeezing service providers for cost concessions.
“I have been forwarded a number of pricing decreases from operators seeking discounts from providers from 20% across the board to 30% requests,” from companies doing completions, Robart said, adding, those are “just a starting point for negotiations. We expect price concession for hydraulic fracturing services in the range of 5% to 10% for 2015.”
Based on what he observed while gathering data about the hydraulic fracturing sector for PacWest Consulting, which was acquired in November by IHS, many pressure pumping companies may have little to give. Making money in shale oil production has required a constant effort to grind down costs.
“There is a lot of equipment that has been worked really hard and needs to be replaced. A lot of it has been working past its recommended life cycle,” he said, adding, “As prices fall, some companies are really struggling. In the next 3 to 6 months I expect some consolidation and some fire-sale acquisitions of smaller players.”
Although some acquisitions and layoffs have been announced, it is still early in the process.
One big acquisition occurred early, when Halliburton agreed to take over Baker Hughes. While the two companies work through the long process to close the deal, Halliburton has been readying itself for a slowdown, with 1,000 layoffs announced in its Eastern Hemisphere operation, and more are expected this year.
More deals are expected as financially strong companies seek out low-priced reserves or equipment in the takeover market. But it is hard to get two sides to agree on a deal when the expected future price of oil covers a wide range.
Acquisitions are not expected to begin until later this year, when the oil markets are less volatile and it is possible to better predict future prices. “Sellers do not want to sell based on USD 70 oil, and buyers do not want to buy assuming USD 90,” Dukes said. “Usually it takes more time for both sides to get more comfortable with prices.”
Low Oil Prices and Stiff Competition Causes of Anxiety for Graduates
Jack Betz, JPT Staff Writer
The largest-ever class of petroleum engineering students in the US is graduating into a job market that was weakening under its weight even before oil prices fell below USD 90/bbl in early October.
Since the mid-2000s, enthusiasm about shale and increased production in the US has flooded universities with students drawn by the promise of high-paying jobs. Now that the number of students pursuing these degrees in the US has exceeded the record levels of 1982 and oil prices have fallen sharply, competition for jobs has increased, according to Dan Hill, head of the department of petroleum engineering at Texas A&M University and SPE Director of Academia.
While many Texas A&M students receive job offers by the end of their final fall semester as a result of internships, there is normally 15% to 20% of the class still looking for permanent employment in the spring. “The rest of the class that is left without a job is certainly facing a more challenging job market than a year ago,” said Hill.
Texas A&M SPE Student Chapter President Jennifer Wisler noticed a slowdown in recruitment in September, during a job fair, months before the oil price decline accelerated. “I think that there were a few companies that started to predict the fall in prices,” said Wisler. “And when we had our career fair, there were way more internships being offered than full-time positions.”
Twenty-eight companies attended the chapter’s fall career fair, and nine of them, or less than a third, made full-time job offers, which was a significant drop compared with previous years, Wisler said. Many of the companies that offered full-time jobs only had one or two positions open, and to make matters worse, some offers were later retracted.
Wisler said that a dire need for more recruiting led the chapter to organize a second job fair, which will be held in February. Normally, the chapter holds one job fair per year, in addition to the university’s general engineering job fair.
Aziz Rajan, president of the SPE student chapter at the University of Houston (UH), also noticed a lack of recruitment at his university’s job fair and said that oil prices are only part of the problem. “I think a major problem for not only University of Houston, but other universities as well, is our size,” said Rajan. Despite being only 5 years old, UH’s petroleum engineering program already has more than 900 students.
In the months before the slide in prices, Rajan noted that more UH petroleum engineering alumni were taking jobs further away from the wellhead. “We see it now with new graduates. They’re not necessarily practicing petroleum engineering. Many are going into less technical careers, like sales,” he said.
The Way Ahead
While the current job market is affecting students around the world, Hill said graduates in the United States will likely be hit the hardest for two reasons.
Firstly, it is less complicated for US operators to slow down in many of the country’s key plays than it is for operators in other locations. “For many places overseas, oil and gas developments are very large, long-term projects, for example, deepwater activities offshore Brazil,” he said. “And these types of things can’t be turned on and off nearly as easily as drilling wells in the Permian Basin.”
Secondly, national oil companies, which are prevalent outside the US, offer cushioning for some countries’ graduates because they are less likely to lay off large numbers of workers when oil prices drop.
In order to improve their chances of finding jobs, Cindy Reece, SPE Technical Director for Management and Information from 2012 to 2014, suggested that students keep their career options open and have flexible goals, especially during slower periods. For example, even though many students may have their sights set on jobs with operators, there are significant benefits to taking more hands-on positions, such as those with service providers, she said.
“At the operator level, you are doing more design and oversight of work,” said Reece. “And you miss a lot if you don’t go through that hands-on stage. By doing so, you know what you’re asking people to do and how best to do it.”
Student chapters also play an important role in boosting graduate placement, which students seem to be recognizing, said Wisler and Rajan, who both reported an uptick in chapter activity during the fall 2014 semester. J.C. Cunha, SPE Technical Director for Management and Information, stressed the importance of student members taking advantage of technical talks, Distinguished Lecturer visits, and chapter events, which provide visibility and networking opportunities.
In the long term, SPE is constantly taking steps to improve student preparedness and consequently enhance their job attractiveness to employers. For example, the “2020 Foresight—Ensuring Educational Excellence for Upstream Engineering Resources” forum, which was chaired by Reece in 2013, allowed SPE leaders to discuss with members of academia the kinds of skills that petroleum engineering graduates need to achieve success.
One major obstacle to preparing graduates for their careers is the increasingly unbalanced student-to-professor ratio, which Reece said is becoming so critical in some places that it threatens to take a toll on the quality of education. To alleviate the problem, SPE continues to offer awards and grants to encourage more engineers to become professors and academic researchers.
