Integrated oil majors are relishing the oil price recovery, posting sharply higher earnings and healthier balance sheets after emerging leaner from the downturn. But they also face a dilemma on when and how to invest for future upstream growth.
Brent crude averaged almost $75/b in the second quarter, nearly 50% higher than year-ago levels and the first time in more than three years that the benchmark grade has held over $70/b. As a result, cash generation is soaring and attention is turning to how producers plan to use their mounting cash piles as prices consolidate above $70/b. Combined, the world’s top seven integrated oil majors reported nearly $40 billion of cash flows from operations in Q2, company filings show, the highest since Q4 2014.
Chevron, Shell and BP all rewarded shareholders with bigger returns, with the first two announcing stock buyback plans. Often justified by executives as a proxy for business confidence and capital prudence, buybacks also boost shareholder returns by mopping up the billions of dollars paid out in scrip dividends to save cash during the downturn.
Critics of returning spare cash to shareholders, however, often claim it shows companies see nothing better to invest in. But the majors may be stuck between a rock and hard place.
Still focused on the mantras of capital discipline and cost control despite rising prices, few producers are willing to risk investment dollars on new projects with future breakevens above $40/b. Uncertainties over the future of oil demand and the clamor for low-carbon energy also weigh on investment decisions. The sector’s recent flurry of spending on power projects is unlikely to drive returns any time soon.
Despite the qualms, the majors are looking beyond the current recovery to restock their upstream portfolios and resources base. They have signaled a return to longer-term conventional projects as well as continuing to focus on shorter-cycle investments such as US shale. BP, which restarted share buybacks last year as it shakes off the impact of the 2010 Gulf of Mexico spill, announced its biggest acquisition in almost two decades just days before reporting Q2 earnings.
Justifying what some saw as a higher-than-expected $10.5 billion price tag for BHP’s US shale assets, BP pointed to financial headroom from tough capital discipline and efficiencies which are set to bring its organic spending in at the lower end of its $12-13 billion guidance this year. Shell, which also bid for the BHP assets and wants to grow its exposure to shale, said it has no intention of risking its balance sheet recovery by overspending on new resources.
“We have a positive disposition to looking at bolt-on opportunities,” CEO Ben van Beurden told analysts last week. “We’ve also been very clear that we do not want to participate in a gold rush… we will look at them, but don’t expect any big splashes.”
Attention may also be turning to restocking resources further out with offshore acreage, potentially big-ticket, long lead-time work which many had shunned after 2014. In July, Shell picked up its first deepwater Atlantic Margin acreage off Mauritania and has also been successful in recent offshore bidding rounds in Brazil and Mexico. Shell, Europe’s biggest oil major, told analysts last week its deepwater business is “performing very well”, noting that the Vito and Kaikias projects in the Gulf Mexico are driving cost savings in terms of wells and completion costs.
Upstream activity is picking up and producers are promising to do more with less as industry costs remain well below pre-2014 levels. Schlumberger, the world’s largest oilfield services provider, reported stronger than expected Q2 earnings driven by a rebound in drilling in Russia and the North Sea. It expects an uptick in offshore activity triggered by higher anticipated spending by explorers. Almost 100 offshore projects worth about $95 billion are set to be sanctioned this year with offshore activity levels close to 80% of their historical highs, according to Norway’s Rystad Energy.
“Higher oil prices, an improved outlook for gas demand and lower offshore development costs are driving this rebound in the industry,” Rystad’s senior research analyst Readul Islam said. Outside the US onshore plays, where higher steel prices are pushing up pipeline costs, offshore drilling rates are stable despite an uptick in demand for new wells, Eni’s CEO Claudio Descalzi said after announcing Q2 results.
In the short-term, most producers may be hard-pressed to keep oil and gas volumes growing. The wave of project startups from investments made during the 2010-2013 period of $100 oil, appears to be tailing off. A year ago, both BP and Chevron posted double-digit Q2 upstream growth. In the last quarter, only Total managed a significant year-on-year volume expansion, while both ExxonMobil and Shell failed to grow output in the period.
Exxon’s production slipped 7% to the lowest in nearly a decade, and the major cut its full-year output guidance by 5% or 200,000 boe/d. As long as cash flows keep rising, however, investors may be happy with majors offering a “value over volumes” proposition.
Most majors are now able to pay dividends and meet capital spending budgets at $50/b oil. A future wave of new, cheaper projects will bring this down further. BP believes its cash flow breakeven will have fallen as low as $35/b by 2021, from $50/b currently, as lower cost projects start to flow.
For now at least, the majors seem to have punted the issue of where to invest for profitable upstream growth. Pushed to choose between buybacks — an internal investment — and being penalized by investors for opening their purse strings too soon, most producers have opted for the former. S&P Platts
Pix: oil majors