Chevron’s bet on big-ticket projects will pay off, eventually
The Gorgon liquefied natural gas project limped into service in March, a year late and over budget. The timing hardly seemed propitious: with oil and natural gas prices still so low, who needs another Australian LNG plant – especially one costing $54bn?
Well, Chevron does; the company has an oilier asset base than rivals such as Shell and ExxonMobil. Gorgon – almost 50% owned by Chevron – beefs up the company’s exposure to gas. Trains two and three should come on stream at six-month intervals, bringing the plant towards its design capacity of 15.6m tonnes a year. More LNG will become available from mid-2017, when production starts at Wheatstone – an 8.9m-t/y, two-train plant owned 64.14% by Chevron. Output from Gorgon and Wheatstone will, over the next few years, make Chevron one of the world’s biggest private-sector LNG suppliers.
Encouragingly, although the two projects might seem pricey and superfluous now, both have solid long-term fundamentals: four-fifths of their combined output has been pre-sold to Japanese and Chinese buyers under deals lasting 20 years or more. The long-term outlook for gas demand across Asia – indeed, globally – is robust.
None of that gets Chevron out of a hole now, though. Gorgon’s estimated $17bn cost overrun plus lavish spending commitments on several other big-ticket projects have sorely tested the company’s financial resilience. Profit, as with other majors, has taken a severe hit: 2015 earnings were $4.6bn, compared with $19.2bn in 2014.
Operational setbacks have hurt too: Angola LNG, for instance, shut down unexpectedly in April 2014 for repairs and maintenance, having only started operating the year before. In the Gulf of Mexico, the failure of mooring equipment last year at the 75,000-barrels-a-day Big Foot project delayed start-up from late 2015 to 2018.
But shareholders have reasons for optimism. First, Chevron is approaching the end of the present cycle of investment. The easing of its investment commitments will coincide with the emergence of new streams of revenue, as projects become operational. Second, Chevron’s balance sheet has proved strong enough to finish projects in development while continuing to pay its dividend, which investors and Chevron regard as untouchable. In the meantime, the company is giving itself more breathing space by reducing its immediate investment commitments: compared with a planned $26.6bn this year, capital spending in 2017 and 2018 will amount to between $17bn and $22bn a year – a cut of up to 36%. Like its rivals, Chevron is cutting costs too and searching for ways to improve operating efficiency. By the end of 2016, for instance, the upstream workforce will be 20-25% smaller than it was in 2014.
While more upstream-focused than its main rivals, record earnings from the company’s substantial downstream businesses in 2015 more than offset losses upstream
Much-needed financial protection has also come from Chevron’s integrated structure. While more upstream-focused than its main rivals, record earnings from the company’s substantial downstream businesses in 2015 more than offset losses upstream. At the same time, the upstream segment has continued to grow in anticipation of an eventual recovery in energy prices: output rose from 2.571m barrels of oil equivalent a day in 2014 to 2.622m boe/d last year. And, in 2015, Chevron replaced 107% of its reserves, achieving a five-year reserves-replacement ratio of 113%.
Still, the company’s leaders admit it needs to improve financial returns. As a result, it has switched its growth strategy away from large capital projects towards “high-return, shorter-cycle and brownfield opportunities”. Boiled down, that means investing more in shale operations, which can be ramped up and down quickly and cheaply – giving producers greater control over their costs, as well as a share of the world’s brand-new source of swing supply. In the US, infrastructure for shale production is already highly developed, removing a fat chunk of costs. Indeed, such is the value of shale to majors’ portfolios that it could be the focus of oil and gas mergers and acquisitions activity globally this year (see pxx).
By the middle of the next decade, says chairman and chief executive John Watson, 20-25% of Chevron’s production could come from short-cycle shale and tight resources. Chevron already has extensive, good-quality acreage in the Permian Basin, with about 2m net acres and resources of about 9bn boe. Outside the US, assets include the Duvernay, in west-central Alberta, Canada, which Chevron describes as one of North America’s most promising shale prospects, and Vaca Muerta, in Argentina’s Neuquén Basin.
Shale will give Chevron a more unconventional look. But at the same time, the big, conventional investments that it has put its reputation on the line to create will start to pay off soon, assuming even a modest recovery in commodity prices. Indeed, judging projects like Gorgon – which has an estimated lifetime of 40 years – on today’s oil price is rather missing the point.
Wallet-busting investments come to fruition
Gorgon and Wheatstone are the engine room of volume growth for Chevron (see main story), but several other large capital projects will add to production soon.
The Jack (Chevron, 50%) and St Malo fields (51%) in the Gulf of Mexico are ramping up steadily towards a peak daily rate of 94,000 barrels a day from 75,000 b/d at present. Combined recoverable resources are estimated to exceed 0.5bn barrels and the fields should be in production for three decades.
The single-train, 5.2m-t/y Angola LNG project, out of action for two years for maintenance and repairs, is expected to come back on line in the second quarter. Also in Angola, first production is expected in the second half of this year at Mafumeira Sul, an offshore project with a design capacity of 150,000 b/d of liquids and 350m cubic feet a day of gas.
West Africa will account for further additions to group capacity this year, as production ramps up at the 40,000 b/d Lianzi oilfield, in a unitised offshore zone between Congo and Angola, and at the 140,000 b/d Moho Nord field, offshore Congo.
Meanwhile, first gas was achieved in January at China’s Chuandongbei gas project and production will ramp up in the second quarter towards its 258m cf/d capacity.
Big Foot (Chevron, 60%) – delayed last year after the failure of mooring equipment – should be on stream in the second half of 2018. With recoverable resources estimated at over 200m barrels, the field is expected to be in production for 35 years.
Other expected start-ups this year include Alder, in the North Sea, and Bangka, in Indonesia. And start-ups scheduled for 2017 and 2018 include Sonam, in Nigeria, Hebron, off Canada’s east coast, Clair Ridge, in the North Sea, and Stampede, in the deep-water Gulf of Mexico.