What next for the global energy industry?
Predicting oil prices has become a dangerous game in the last few years, with many a reputation being dented by forecasts that turned out to be too optimistic or the opposite in an historically unsettled period affected by many variables.
It doesn’t help much that analysts’ views vary significantly, from as low as US$40 per barrel (pb) to as high as US$65pb a disparate range that hardly makes life any easier in the C-suite.
A typical prediction – and one of the most recent – comes from Moody’s Investors Service, which in January estimated a range of US$40-US$60 pb through 2018, despite OPEC extending its production cuts until the end of the year.
Will a US$20 range between top and bottom discourage upstream and downstream investment or encourage it? According to Zacks Equity Research in a report released in January, based on exploration budgets for 2018 the indications are that activity will stay roughly the same as in 2017. Zacks believes a sustained US$60pb is the benchmark that will catalyse spending on exploration in the newer, deep-water frontiers. However in the same vein, consultancy Wood Mackenzie predicts that the majors will cut exploration spending in 2018, making it the fifth year in a row of upstream cuts.
But exploration budgets don’t tell the full story. As we’ll see, industry-wide improvements in efficiency and productivity since the oil price crisis mean that more is being done with less. And while some consultants such as Rystad Energy bemoan a steady decline in the rate of discoveries, identifying an exploration strike rate of 35 per cent today compared with 40 per cent a decade ago, there’s still a torrent of investment for producing fields.
Even at US$40-US$60 a barrel, the burst of M&A action in 2017, especially in North America, is looking increasingly astute. As a wealth of third-party research from 1Derrick, Deloitte and others shows, this stream of CapEx will fund exploration throughout 2018 and beyond, barring major price shocks. In a reference to a hectic first quarter in 2017 in the Permian that attracted US$17bn by value in investment, 1Derrick’s chief operating officer Mangesh Hirve explained in a late-2017 report that buyers were desperate to buy a slice of what may yet prove to be the best tight oil play in the world before it’s too late.
But the money kept coming in the ensuing months. By half- year in 2017, about US$127bn worth of M&A by value had been confirmed. Another flurry of investment activity in late 2017 will lead to more upstream assets in the years hence.
All sectors of the industry – upstream, oil field services, midstream and downstream – were the beneficiaries. Although the US booked the lion’s share of the deals in 2017, Canada saw most of the rest. Its oil sands and deep- basin assets attracted a great deal of the smart money that will fund exploration for years to come.
Interestingly, much of the flood of investment that will propel exploration in the near future happened as oil prices fell. As PwC’s Seenu Akunuri, the consultancy’s leader in oil and gas valuations, pointed out, these investors were thinking long-term. Their expectations are that breakeven costs will probably continue to be lower for longer, making viable a price point of around US$50.
The investment into exploration hasn’t been confined to North America by any means. China’s state-owned majors are belatedly pumping resources into the development of unconventional onshore gas fields and are catching up fast on the back of technological breakthroughs that, they say, will spur production in coming years. According to China’s National Bureau of Statistics, shale gas output is rising at double-digit rates every quarter (in one month it grew by over 50 per cent, albeit from a low base) while the volume of proven reserves is expected to exceed 1.5 trillion cubic metres by 2020 as new fields are discovered, quite enough to fuel production for decades.
Leaving aside the impact of oil prices on upstream activities, researchers cite the relentless demand for hydrocarbons that is up to a point divorced from price. In the next five years, notes the International Energy Agency, China and India alone will rely on oil, domestic and imported, right through until 2040. As the IEA highlights, non-OECD Asia will remain the major source of growth in demand for oil for many years.
Once again, China tells us a lot. In 2018 China National Offshore Oil Corporation (CNOOC) expects to drill 132 exploration wells in 2018 and will bring five projects to production. The major certainly isn’t trimming its exploration budget – this year CNOOC will spend between US$11.1 billion and US$12.7 billion, the company’s highest capex in four years.
Elsewhere, most of the upstream activity will be in deep- water basins such as Mexico, Brazil and Guyana where bonanza finds have been made in the last few years, encouraging new drilling. Belying gloomy statistics about the rate of discoveries being in decline, ExxonMobil hit oil off Guyana no less than three times in 2017 and has enough hydrocarbons in hand there to keep it going for years. Promising wild-catting is going on in Mexico; for instance in the country’s first offshore pre-salt well, where Pemex is drilling in the shallow waters of the Campeche Basin. Finally Egypt promises to become an important upstream focus after opening bids for various areas in the Red Sea where it’s conducting seismic surveys. The government has signed 12 new oil agreements and is set to agree a lot more in the coming years as Egypt aims for self-sufficiency in natural gas.
Today’s oil and gas industry is in a better position to take advantage of rising prices than it was before the oil-price shock. As McKinsey pointed out in a report in December 2017, many upstream operators have made significant performance gains in recent years, with production costs across the sector down by 30 per cent and production losses by 15 per cent since 2014, the latter being heavily influenced by digital technologies that, for example, improve the quality of maintenance. Meantime the incidence of accidents, another heavy capital and human cost, is down by an impressive 33 per cent.
In another example of improving technologies, during the tough years the FPSO fleet used the opportunity to modernise itself. Today’s “floaters” are more durable, versatile, productive and cost-effective than even ten years ago, so are now better suited to contemporary oil economics.
And whether it’s for FPSOs or other o shore infrastructure, in the quest for greater efficiencies operators are demanding commonalities in design in a process that’s akin to assembly-line production. One of the leaders in the trend towards standardisation is Petrobras, which has been using the same conversion template in its last five FPSOs, all of them designed for a production capability of 180,000 bpd. Similarly, Italy’s Saipem is converting two FPSOs for deployment in o shore Angola in 2018, both of them designed for the same water depths and storage capability.
Latterly, FPSOs are being deployed to smaller, clustered oil pools where they are extracting hydrocarbons in a sequential process, moving rapidly from one to the other. This is far more cost-effective and efficient than constructing and perhaps dismantling a series of fixed platforms. Without these more versatile FPSOs, the pools would probably not be viable.
In perhaps the most extreme example of cost-effective exploration, Malaysia’s Petronas has deployed what it calls a marginal mobile production unit, or MaMPU, that will tap low-margin, o shore minimal fields where hefty capital expenditure may not be justified. The oil and gas equivalent of a pick-up truck, the MaMPU was converted from an oil tanker into a mini-FPSO in just eight months.
As Wood Group pointed out in a late 2017 report, it’s nimble vessels such as these that are helping rewrite the economics of exploration and production at a time when short-term, price-related decisions are the order of the day.
In a similar example, in late 2017 Petrobras commissioned an FPSO that will in four years’ time be anchored at the new Mero field, 180kms o the coast of Rio de Janeiro, where it will hook up as many as 17 wells. In doing so, the Brazilian oil giant will be able to spread its investment for maximum operating expenditure.
There’s also more interest in conversions – that is,of existing vessels to FPSOs. Markit expects seven construction projects will be awarded in 2018 on top of the eight contracts already under way in 2017. Because they’re faster and cheaper, conversions of (usually) VLCCs are the preferred route in the present environment. As Wood Group notes, single-hull conversions can be done at ten per cent of the cost of newbuilds and, depending on the how big the job is, can be in operation within two years.
Although there are fewer of them compared to conversions, the newbuilds are getting bigger. Demonstrating the trend, Samsung Heavy Industries-built Egina - which will start operations 200kms of the Nigerian coast in late 2018 - is the biggest FPSO yet. With a storage capacity of 2.3m barrels, her construction will consume US$3bn and will take about four and a half years.
But generally, as McKinsey’s researchers also show, new technologies and improved ways of working are resetting top quartile performance. And that’s especially true of the digital technologies such as analytics that are sweeping through the industry. In a report in December 2017, McKinsey calculates that the introduction of digital technologies may improve total cashflows by a thought-provoking $11 a barrel across the o shore oil and gas value chain. On that basis, predicts the consultancy, digital technologies would add US$300bn a year in revenues by 2025.
Because the industry isn’t the same one that entered the oil-price crisis, it’s collectively more con dent about its future, even if prices rise only modestly. In the British part of the North Sea, there have been several acquisitions that seem to demonstrate that this area remains economically viable, and it is understood that that some companies have now trimmed costs to a breakeven production figure of US$15 pb.
Indeed, the death of the North Sea has been greatly exaggerated. Far from being a decommissioning graveyard, the new breakeven benchmarks being achieved by upstream operators are giving some of the more mature fields a new life, as several investments show. As Deloitte points out, nearly US$6bn was invested in the UKCS in the first half of 2017 in the form of asset and corporate acquisitions.
The UK government is also fully engaged in ensuring that the life of the North Sea fields is extended to their limits. Operators cannot shut down a field without the authorisation of the Oil and Gas Authority and the government body won’t sign off while there’s still hydrocarbons to be had. That level of scrutiny has served to lengthen the average life of the UKCS fields by an average of five years beyond the original plug and abandon date.
Yet the “decom” industry has years of pro table work ahead of it. In the UKCS, Oil & Gas UK estimates that between £8.5bn and £10bn will be spent on decom alone. And looking further out, the trade body’s latest report estimates £17bn will go into decom work between now and 2025.
So because today’s industry is more streamlined, perhaps the exploration budget is no longer the most important indicator of upstream activity. However, for the record, there’s still plenty of exploration money in the kitty. According to Wood Mackenzie, global investment in exploration will hit US$37 billion in 2018. Although that’s down seven per cent from a year earlier and over 60 per cent below the 2014 peak, it will finance most – or even all – of the exploration that’s needed.
Selwyn Parker is a freelance journalist and a regular contributor to Petroleum Economist magazine.
