The majors’ plans for 2019 look remarkably similar on the surface, but there are key differences
Share price performance since the start of 2016 would seem to suggest that the majors have been taking radically different approaches. BP and Shell have been tearaway successes (see Fig1.), ExxonMobil and Eni have lagged and Total and Chevron have been somewhere in between.
But these differing trajectories are all the more surprising at a time when the general thrust of the firms’ strategies is relatively similar. “The over-riding driver is the same-making portfolios more resilient to lower prices, boosting margins via high-grading, and moving down the cost curve,” says Tom Ellacott, senior vice-president for corporate research at consultancy Wood Mackenzie.
At the same time, the subtle differences in approach may be increasing. “I would argue that we are seeing more differentiation. ExxonMobil is implementing a bold investment-led long-term growth strategy, while all the other majors are keeping budgets flat. Chevron is bedding down in the Permian, but Total and Eni are sticking to their strengths in conventional E&P,” says Ellacott.
Blake Fernandez, senior research analyst for integrated oils and refiners at Houston-based investment bank Simmons, agrees that ExxonMobil’s strategy in particular stands out, and also cautions about reading too much into share price solely over the past three years. If you extend the timeline back to when the Saudis shifted policy in 2014 and crude prices collapsed, ExxonMobil and Chevron were the go-to stocks and outperformed the European majors, he says.
Historically, they are seen as having stronger balance sheets and offering better returns. As oil prices have stabilised and recovered, the Europeans have been clawing back that ground. “On forward multiples, the group has largely moved back into line, with maybe some slight over-performance from some of the Europeans. Chevron had the most exposure to the Permian and would have been rewarded for that. ExxonMobil surprised the street at its strategy day by announcing an escalation in its spending,” says Fernandez.
Of all the majors, ExxonMobil is the only one not repurchasing shares, which is a negative for the share price in Fernandez’ view. In its third quarter results conference call, the firm stressed that paying a growing dividend was part of its capital allocation strategy and that, if there was excess cash, it would distribute it, pointing to over $220bn of dividends since the Exxon-Mobil merger. But it is prioritising its portfolio investments, particularly in accretive projects, and wants to restart buy-backs only when it can commit to long-term sustainable distribution.
Fernandez understands the firm’s caution. In March, it committed to boosting capex to $24bn in 2018, $28bn next year and an average of $30bn from 2023 to 2025. “It has got this big ramp-up in spending, the impact of which already has to be factored into the balance sheet, and, just in case commodity market conditions see another downturn, then there are cashflow implications. We see the majors needing a breakeven price somewhere around $55/bl Brent and ExxonMobil is near the top end of that range. So, we think we would need Brent sustained at over $60/bl to make buybacks work. The projects are stacked up and the spending is locked in, so it is not leaving ExxonMobil with much flexibility,” says Fernandez.
Another analyst is unconvinced that a buy-back strategy should be rewarded. “Buy-backs are currently in vogue, and have been rewarded by the equity markets,” says Rob West, a partner at London-based research firm Redburn. “However, our own deep-dive modelling of the projects shows more value may be created by re-investment. If we measure the companies on a net asset value (NAV) basis, ExxonMobil and Eni have created the most ‘new value’ during the downturn. We think this will be rewarded over the long-run.”
The M&A space is another where the majors’ strategies look broadly similar-selling off existing assets with a lower rate of return and trying to add higher grade assets into the portfolio. The consensus is that 2019 will not see any bold moves to break out of the pack with a major deal on either the acquisition or divestment side.
“We would expect a high level of high-grading activity. There are also big discovered resource opportunities up for grabs in Brazil and Qatar, and consolidation is likely to continue in the Permian,” says Wood Mackenzie’s Ellacott.
“It is difficult to see an awful lot of benefit in corporate M&A; E&P consolidation seems more likely,” says Simmon’s Fernandez. “Also, in the downturn, a lot of companies slashed their general and administrative costs, which is where you get a lot of the synergies in deals. And there is the dogs and cats issue-with a corporate deal you might get lots of things you like but also things you don’t like that you then need to re-divest. I think precision M&A is most likely, for example portfolios in the Permian, or E&P assets consolidated in a particular basin.” LNG projects, the Gulf of Mexico and Brazil could be likely focus areas for these precision deals, in Fernandez’ view.
The US unconventional Permian basin has seen a slew of deals as the majors beef up their presence there. Chevron and ExxonMobil, perhaps unsurprisingly given their US roots were the leaders, with the latter’s acquisitions, including US independent XTO and companies owned by the Bass family, driving the share of ExxonMobil’s global oil produced in the US from under 20pc to approaching 25pc (see Fig2.). BP joined the Permian party in a big way in July with a $10bn+ deal to buy assets from Anglo-Australian BHP.
There is some debate over whether the Permian has become too dominant in firms’ thinking. “To some extent, there is a limit,” cautions Fernandez. “If you look at Chevron’s Permian growth profile out to 2022, reaching 650,000bl/d, in terms of a percentage of their expected overall portfolio, that’s pushing up to about 20pc. Firms don’t want too much exposure to a particular geography or geology, they want an adequate balance in the portfolio.”
Ellacott is more sanguine. “It’s going to depend on specific corporate strategies-the outcome will be that investors can choose between majors with a high degree of exposure to the Permian and others that focus more on conventional E&P,” he says.
“Every serious major will need to be a part of the unconventional revolution, one way or the other,” says West. There are, of course, options other than the Permian to gain this exposure. Total is continuing with its planned investments in the Vaca Muerta shale play in Argentina, given that it is low cost unconventional resource. But it confirmed in its third quarter results conference call that, due to the economic situation in Argentina, in particular its lowering of the domestic gas price and its currency travails, it has not been investing beyond its current commitments.
It remains to be seen whether Total, Shell and Eni follow BP’s lead in looking to increase their exposure to the Permian’s prolific Midland and Delaware basins. “On US unconventionals, Chevron and ExxonMobil have been leading and the Europeans trailing. Obviously, BP has looked to close that gap with the BHP deal. The rest of their peers may have gaps to fill,” says Fernandez.
Trimming the fat
Divestments are at least as important as acquisitions within majors’ 2019 strategies as part of high-grading portfolios. Deals might well be seen even before year-end, with BP needing to shed $3bn of assets and Total $1.5bn to hit 2018 targets. In terms of what will be put on the block, “it is likely to be a mix of non-core country exits, the sale of low margin and tail-end assets and rationalisation of more carbon-intensive assets”, according to Ellacott.
Fernandez expects the upstream sector to be the focus of divestment, but the pace of asset sell-offs to cool. “If we rewind a couple of years—when the oil price collapsed—firms were struggling to fund both their capex and dividend commitments out of cashflow. So they were in effect selling off assets to help fund the dividend where cashflow was falling short,” he says.
“ExxonMobil didn’t really participate in that to the same extent, but it’s now looking to be more aggressive in selling upstream assets. Total has also said that it sees a good environment for selling upstream assets. With these businesses, you are always going to get some churn, say $3bn a year, but I think the divestment levels will be scaled back from their recent elevated levels. And it was much more focused on the downstream, now it will likely evolve more towards the upstream,” Fernandez continues, predicting that more mature, legacy Gulf of Mexico (GoM) and North Sea assets will remain a divestment focus
Redburn sees particular value in divestment for BP, having recently broken the firm’s business down across 45 different sub-segments, estimating earnings, cash flow, capex and free cash flow for each one. “We think there is $70bn of ‘hidden value’ in the company. Excitingly, the company is going to start unlocking it with divestments, following the BHP deal. Prime candidates include [Argentinian joint venture] Pan American Energy, Russian opportunities, lubricants and pipelines, which are not always fully visible to the market,” says West.
One area in which analysts’ views for 2019 diverge is the impact of the oil services sector and whether the majors will face cost inflation or further deflation. “Disposals will still drive break-evens down, but it is unlikely we will see much more cost deflation and, in some areas like the Permian, costs are increasing,” says Ellacott.
Fernandez agrees. “I think we have hit a bottom, on a couple fronts. Capex estimates are up, only by mid-single digits, but they are rising from this year and next. And we are hearing clear signals of cost re-inflation—for example, Chevron is pointing to a 5pc increase in organic capex and Conoco is also seeing a slight increase in capex,” he says. “On the services side, there is only so much blood you can get out of a turnip, there is not much more room to squeeze there.”
But Redburn’s West takes a contrarian view. “We think cost deflation will continue apace, driven by shale. Having reviewed over 20 society of petroleum engineers (SPE) papers this summer, we still think productivity can double from here, unlocking world-changing production potential. This will force continued cost discipline on other projects, and even fiscal reform across international projects, otherwise they will struggle to attract capital,” he says.
And his view that there is more potential for cost savings through productivity gains is offered some support by a research note on the North Sea from London-based brokerage Stifel, which concludes that most cost reduction in the UK’s offshore oil and gas industry in 2014-17 was cyclical, not structural. In Stifel’s view, most cost reduction was the result of supply chain deflation rather than improvement in working practice or technological change. The “dramatic reductions in UKCS costs seen in 2015-16 are in line with what we should have expected from looking at the wider industry backdrop; that is to say, almost all of the cost reductions have been cyclical and the UKCS did not, in relative terms, become a more
attractive place to invest in that period-rather, oil assets themselves became investable again, and the UK was a straightforward beneficiary of this”, according to the Stifel note. But its expected outcome is not that the opportunity to make more structural changes could allow yet lower operating costs, rather the lack of these changes will send costs higher again with an uptick in the oil price cycle.
Spend a penny
Going forward, Redburn expects Total to deliver 6.1pc/yr production growth in 2017-20 off the back of its current plans (see table) while it judges ExxonMobil to have the best portfolio of new projects, with an average internal rate of return (IIR) of 25pc, which will mean it burns £3bn less of free cash flow by 2020 than currently. In contrast, it sees Shell’s long-run production growth still lagging other majors.
While the majors have been reasonably successful with the drill bit in recent years, analysts’ views also diverge on whether firms have spent and will spend enough to keep their project pipeline fully loaded. “The companies with the best portfolios might nudge budgets up a touch but generally we would expect them to be relatively flat-the high-grading effect will play the key role in delivering decent returns and value creation,” says Wood Mackenzie’s Ellacott.
But Fernandez thinks firms should look at spending more. “In the downturn, exploration budgets were slashed, which is not surprising when you look at the five-to-ten-year timescales between discovery and first oil. If you did not need the barrels in the market anytime soon, it made sense to cut that spending,” he says.
“So, while the industry might be successful with the drill bit relative to what it’s spending, there is a major need for re-investment in exploration or that [lack of investment] will come home to roost. We are either going to need a wave of consolidation to replace the barrels being produced, or companies are going to have to up the ante on exploration,” Fernandez continues.
“If we look at average finding and development (F&D) costs for the integrateds of $20/bl on an organic basis, and the amount they are spending on exploration, they are only going to replace 65-70pc of reserves at those levels. So, either spending needs to ramp up or F&D costs need to come down. When we see those numbers for 2018, maybe in the first couple of months next year, that will be pretty telling,” he predicts.
Hit the gas
Gas is any area where, although all the majors to some extent share a broadly similar goal of upping their exposure on a long-term basis, there is significant divergence in the recent strategies. Shell made the biggest move with its 2015 acquisition of BG, while Total has been the most recent significant M&A mover, snapping up French utility Engie’s LNG portfolio in November 2017. Eni’s East Mediterranean success, in particular the giant Zohr gas discovery, could return it to exporting Egyptian LNG as soon as next year, while Chevron appears to be taking a slight pause after completing its Gorgon and Wheatstone Australian mega-projects.
BP may take FID on its Tortue floating LNG facility on the Senegal-Mauretania maritime border next year, which, along with Total’s GoM Cameron trains 4 and 5, could be the only major-backed LNG projects taking FID next year. ExxonMobil has future LNG plans in Papua New Guinea and Mozambique, as well as its GoM Golden Pass conversion-to-export project. But these are all a few years away and in the meantime the firm has actually seen its global gas production drop from over 12bn ft³/d in early 2014 to just 9bn ft³/d (see Fig3.), mainly driven by a drop in its US gas production. ExxonMobil is hopeful of being chosen as a partner in the Qatargas LNG expansion, but this is an ambition it shares with more than a few of its peers.
“Shell has likely brought a lot of the BG synergies to fruition, but Total probably still some way to go with the Engie assets,” says Fernandez. He is not overly concerned that ExxonMobil lacks timeframes for its future projects, but instead identifies Chevron’s future LNG prospect as potentially more worrying. “While Chevron does have the recent Australian projects now in the portfolio, it does not look as exposed and there is not a lot of future growth there. So it may look to take some specific steps to remedy that,” he says.
While BP’s future LNG project pipeline, outside of Tortue, is not extensive, Fernandez warns that this should not distract from the firm’s overall gas ambitions. “BP does have a stated strategy that it wants production to be 60pc gas, so it is making a decisive move in that direction. But much of BP’s gas is not LNG, but more traditional pipeline gas for domestic markets, for example in Egypt and Oman. These are more contractual projects, we do not get a lot of visibility on the pricing mechanism, whereas, with LNG, you have the market price and the oil-linked contracts,” Fernandez says.
He does not expect another game-changer like the BG deal to emerge in 2019. “It is probably less about buying a portfolio than identifying specific projects and partnering up on those, like Shell in Canada. It will be interesting to see how FLNG develops, that could open up smaller discoveries that it would not have made sense to develop separately in a conventional project,” Fernandez says.
Redburn’s West foresees a significant price trend in the global gas market that could have a significant impact in 2019. A rise in coal and European CO2 prices have driven European gas prices higher this year and Redburn expects this to continue and even-due to a glut in fuel oil as the IMO 2020 regulations decimate its marine fuel demand base—a switch to higher LNG prices in Europe compared to Asia. Many parts of Asia retain fuel oil-burning generation assets in their power mix, pushing out gas demand.
Total and ExxonMobil should be beneficiaries of this trend, says West, as both are 60/40 Atlantic Basic/Pacific Basin focused in their portfolios. Total, through its 23pc stake in US project developer Tellurian, should reap the reward if the Driftwood LNG project progresses as part of a wave of GoM export projects whose economics would be transformed by an Atlantic Basin LNG premium, while ExxonMobil should also benefit from Golden Pass becoming more attractive.
The proximity of Eni’s new North African production to Europe would be a boon for it, while Shell has 35-41pc of production exposed to international gas pricing compared to an average for the major of 26pc, says West, so it too would see improvements in its bottom line. Again, Chevron is seen as a straggler, just 22pc of its production exposed to international gas pricing.
Source; Petroleum Economist