Pipeline Magazine’s Nadia Saleem writes about U.S. benefactors of higher oil prices and the global implications of its rising exports
Higher oil prices thanks to an OPEC-production curb have triggered a chain of events in the United States, leading to increased oil and gas development, exports and recruitment with implications on its global market share.
OPEC in its April monthly report raised U.S. supply growth forecast by 200,000 barrels per day (bpd) to 540,000 bpd for 2017.
Increasing U.S. oil and gas production are a sign of caution to OPEC, who worked hard to negotiate a pact with over 15 countries to cut output, pushing crude prices up above the breakeven levels for U.S. producers.
U.S. is now reaping the benefit of oil prices above $50 a barrel, with drilling activity on the rise. U.S. drilling rigs have risen to 824 in the week of March 31, compared to 374 in the year-ago period, Baker Hughes data showed.
However, OPEC is considering ways to deal with rising U.S. production, which is filling the vacuum left by output curbs resulted after much negotiation between OPEC-member and some non-member countries like Russia and Iran.
“It can be expected that any move towards higher prices will likely lead to resurgence in US tight oil (shale) production from the major shale regions,” OPEC said.
“The number of drilling rigs and the reactivation of companies’ spending are the two most important factors leading to an expected output surge in the coming months.”
U.S. CRUDE EXPORTS
In 2016, U.S. crude oil exports averaged 520,000 bpd, 55,000 bpd (12 per cent) above the 2015 level, U.S. Energy Information Administration (EIA) data showed.
Following the removal of restrictions on U.S. crude oil exports in December 2015, the U.S. exported crude oil to 26 different countries in 2016, compared with 10 countries the previous year, EIA said in a report.
In 2015, 92 per cent of U.S. crude oil exports went to Canada, which was exempt from U.S. crude oil export restrictions. After restrictions were lifted, Canada remained the top destination but received only 58 per cent of U.S. crude exports in 2016.
Aside from Canada, European destinations such as the Netherlands, Italy, United Kingdom, and France rank high on the list of U.S. crude oil export destinations. The second-largest regional destination is Asia, including China, Korea, Singapore, and Japan. In 2016, the United States exported to eight different Central and South American destinations, including Curacao, Colombia, and Peru.
EIA said several factors contributed to the rise in U.S. crude oil exports in 2016. Increased crude oil imports in 2016 substituted for some domestic crude oil at U.S. refineries, allowing higher exports despite lower U.S. production and increased refinery runs. Low tanker rates for most of 2016 helped to narrow the price spread needed to allow for an economically attractive trade between the United States and overseas markets. With the average daily volume of crude imports more than 12 times the average daily volume of crude exports, many tankers were available for back-haul voyages at rates significantly below regular tanker rates, likely further reducing the cost of reaching export markets.
While short-term crude exports are on the rise, gas is not far behind.
In its long-term outlook, the International Energy Agency (IEA) said in a report earlier this year that United States will go from being a net importer of natural gas at 2014-end (1 trillion cubic feet) to exporting 3.5 trillion cubic feet by 2020 and 5.5 trillion cubic feet by 2030 as a net position.
Meanwhile, it’s not just a higher oil price triggering increased exploration and production activity. A sharp drop in project cost for deep-water drilling, is likely to compete with US tight oil play, especially in the US Gulf of Mexico, where three large projects have already been approved.
A recent Wood Mackenzie report said project costs have fallen by just over 20 per cent since 2014.
Assuming a 15 per cent internal rate of return hurdle (NPV15), 5 billion barrels of pre-sanction deep-water reserves now breakeven at $50 per barrel of oil equivalent (boe) or lower, it said.
By comparison, there are 15 billion barrels of tight oil resource in undrilled wells with break-even price of $50 or lower at a 15 per cent hurdle rate in Wood Mackenzie’s dataset.
However, the playing field between tight oil and deep-water is about to get a lot more level. “There is still considerable scope to drive deep-water break-evens lower through leaner development principles and improved well designs, but in tight oil cost inflation is back with a vengeance,” the report said.
Wood Mackenzie estimates that a further 20 per cent cut in current deep-water costs would bring 15 billion barrels of pre-FID reserves into contention, on par with tight oil. The deep-water value proposition will strengthen as tight oil cost inflation returns. A 20 per cent rise in tight oil costs would mean that the two resource themes effectively have the same opportunity set measured by volume in the money at $60 per barrel of oil equivalent.
“We are at last beginning to see the first signs of recovery in deep-water, driven primarily by cost reduction and portfolio high-grading. Projects in the US Gulf of Mexico in particular have made significant strides, with many reducing NPV15 breakevens from above $70 per boe to below US$50 per boe,”said Angus Rodger, Asia-Pacific upstream research director at Wood Mackenzie.
“This is not just a result of cheaper rig day rates. Of far greater impact are the steps the industry in the Gulf of Mexico and elsewhere have taken to re-evaluate project designs and improve well performance. We are now seeing scaled-down projects emerge with less wells, more subsea tie-backs, and reduced facilities and capacities – and this all translates into lower breakevens.”
The slowdown has also changed the structure of the deep-water industry. While it is slowly getting leaner, it is also getting smaller. Over 70 per cent of the 45 pre-FID projects targeting sanction over the next few years are operated by just eight companies – Brazil’s Petrobras and the seven majors (ExxonMobil, Chevron, Shell, BP, Total, Eni and Statoil). This is due to the exit of many independents from the sector because of either cost pressure or a re-allocation of capital to tight oil plays.
In a capital-constrained world, fewer operators inevitably means less deep-water projects flowing through to sanction. Only the most cost-competitive projects and regions will attract new investment.
Driven by the optimism from higher oil prices, producers with exposure to the US Lower 48, and particularly those active in the Permian basin tight oil play, are loosening their purse strings and setting ambitious growth targets, according to a Wood Mackenzie report.
However, caution is intact with larger operators exiting current capital intensive phase of investment, such as Total and Chevron – these will see spend continue to trend down.
Wood Mackenzie’s analysis of the 2017 guidance issued during the Q4 reporting season indicates that approaches to capital expenditure and production targets this year depend, in large part, on a company’s operational focus.
The research firm expects to see upstream investment increase this year for 99 of the 119 companies that have so far announced their budgets, a reflection of the severe cuts made in 2016. Those that are cutting capex are among the largest in the sector.
In aggregate, the 119 companies covered by the report plan to spend $25 billion more in 2017, a year-on-year increase of 11 per cent. This figure is subject to revision, as more companies announce their spending plans, the report said.
Those companies focused on the US have booked the largest increase in planned spending, with budgets set to rise 60 per cent year-on-year, accounting for $15 billion of additional investment. Among those companies that will increase spend are tight-oil specialists Pioneer and EOG, underlining the attractiveness of the Lower 48’s shale plays, even at current prices, Wood Mackenzie said. Bigger budgets are also expected in Canada, Latin America and Russia.
“For many companies, 2017 will be about focusing on returning to growth. The 98 companies that have announced production guidance for the year expect to produce a combined 1 million boe per day more than in 2016, year-on-year growth of about 5 per cent,” it said.
Some of that growth will come from acquisitions. The US-focused group of companies account for 800,000 boe per day of the total, a 15 per cent year-on-year increase. Internationally-focused companies, however, have forecast overall production declines this year.
Another obvious benefactor of higher oil prices is recruitment. Service companies within the shale business are now starting to recruit again and are expected to do so in offshore later this year after a massive workforce reduction in the oilfield service industry during 2014 to 2016, Rystad Energy said in a research report.
The North American shale industry in particular, took a hard hit with the lower activity levels. Two of the largest land drillers, Nabors Industries and Helmerich & Payne, announced several staff reductions resulting in an overall reduction above 50 per cent. The Big Four, all exposed to the US land market, were forced to lay off between 30-40 per cent of their workforce. Companies exposed to more of the international market have cut more modestly, in the range of 20-30 per cent.
“Among the top 50 service companies, around 300,000 workers or 35 per cent of the work force, were laid off since 2014. However, the negative trend is about to turn and over the last few months we have seen more job-postings in North America from companies such as Weatherford, Nabors and Precision Drilling, among others. Last week, Halliburton announced its plan to add 2000 jobs to the pressure pumping and cementing business” said Audun Martinsen, VP of oilfield service research at Rystad Energy.
The offshore industry in general has been more resilient, but 2016 saw a larger step-up in downsising. FMC technologies reduced its staff by 1,000 as an initiative of cutting costs prior to the Technip-merger, and in October 2016, Saipem revealed that 800 jobs needed to be cut in Europe. Recruitment is expected to increase once the exploration and production (E&P) spending increases. Rystad Energy expects shale focused operators to increase their spending by 30 per cent in 2017, while offshore spending will grow from 2018, associated with increased FID activity.
“With more projects offshore being revived in 2017, we expect the offshore lay-offs to stabilise and start to increase later in 2017. Already we see this trend in Norway and it is only a question of time before it starts elsewhere. The race for the best hands and brains has started in the industry and the companies that have laid off people in a responsible manner are likely to have a competitive edge going forward,” said Martinsen.