Oil survivors

Around $380bn of capital expenditure has been cut or deferred from 68 of the world’s largest upstream oil and gas projects, according to consultancy Wood Mackenzie. That has pushed back new production of 2.9m barrels a day until at least 2020. With fewer projects coming online, the global rig count has halved. Major US producers including Anadarko Petroleum (US: APC), ConocoPhillips (US: COP) and Noble Energy (US: NBL), as well as Italian giant Eni (IT: ENI), have cut their dividend payouts to shore up cash flow. Other balance sheets have been placed under even greater strain: between July 2014 and December 2015, 35 US explorers and producers with cumulative debts of $18bn filed for bankruptcy protection. That trend may now accelerate. Hedges that offered some support to producers in 2015 are starting to expire and cannot currently be negotiated for more than $45 a barrel for a 12-month futures contract.

Politically, the saga has reminded the world of Opec’s vestigial power (the Organization of the Petroleum Exporting Countries), while raising major questions over its future. Saudi Arabia, which originally increased supply in a bid to halt US producers’ growing market share, is now struggling to co-ordinate a freeze in production that could boost prices to levels desperately sought by fellow Opec members.

Then there are the broader effects. Countries that are heavily reliant on oil exports, including Venezuela and Nigeria, are facing serious economic pain. Conservative estimates suggest more than 250,000 people working in the industry have lost their jobs, badly hitting energy-focused regions such as North Dakota and Aberdeen. However, because most countries are oil importers, the International Monetary Fund estimates that the price fall has probably been good for global growth.

But that’s another story. This article is for those investors prepared to survey the decimated sector for value, and for the larger numbers who have bought or inherited shares in the oil majors and are now concerned about their ability to sustain their dividends. First we ask where and when the market is going to return to some degree of normality. We conclude with a list of stock picks that have the balance sheet and operational strength to survive the rebalancing.

All in the balance – the flight from contango

In a recent interview broadcast on Bloomberg Television, Vitol chief executive Ian Taylor said that any substantive retracement in the price of crude oil could be “several years away”. Although the head of the energy trading giant revealed that internal analysis of the global crude market pointed to “a tightening in the second half of the year”, the aggregate effects of the industry-wide reduction in capital budgets probably won’t become apparent until 2018-19.

Contrary to the view of some insiders, Mr Taylor doesn’t foresee a sharp rebound in prices, particularly given the state of global inventories. January figures from the US Energy Information Administration (EIA), for example, put domestic inventories approaching an eight-decade high at 503m barrels; equivalent to five days of estimated global demand in 2016 and 132m barrels in advance of the 2011-15 January average.

This obviously has knock-on effects. If inventories are bloated but still rising, the cost of storing crude oil usually increases. In oil futures markets, where traders routinely buy commodities for specific delivery times in future months, increased storage costs often mean that long-term deliveries are priced higher than near-term deliveries; a situation known as contango.

A market routinely manipulated

The imbalance rests primarily with the supply side of the equation, although it’s conceivable that markets could move back towards equilibrium at an accelerated rate if some agreement was made on production cuts. Intriguingly, the Vitol chief believes that a compact between Opec and non-Opec producers is “a real possibility”. A February accord on production levels between Saudi Arabia and Russia failed to do much, but all eyes are now trained on 17 April, when a meeting of Opec and non-Opec producers will take place in Doha.

We shouldn’t forget that we’re talking about a market that has been routinely manipulated, so a compromise deal on production rates cannot be ruled out, in much the same way that we can never discount sudden supply-side shocks – the Yom Kippur War of 1973 provides a prime example. But leaving aside geopolitical influences, it is worth examining the extent to which crude prices could retrace once traders accept that market fundamentals are moving towards equilibrium.

A forecast decline in non-OPEC output

The EIA estimates that the global crude oil surplus came in at 1.9m per day in 2015, marking the second consecutive year of inventory build-up. This oversupply is forecast to rise by an additional 0.7m barrels a day through this year, before markets start to re-balance in the second half of 2017. There has been much talk of new Iranian barrels hitting European markets, although it seems likely that the 0.5m barrels flowing out through the Strait of Hormuz will be countered by the anticipated fall-away in US shale output over the same period. And some industry commentators believe that Tehran has already been exporting crude volumes in excess of the trade sanctions through Iraqi channels.

While all this is playing out, global consumption of liquid fuels is expected to grow by 1.4m barrels a day, with a similar rate of increase predicted through next year. On the other side of the ledger, the rebalancing of crude markets should hasten as a consequence of a forecast decline in non-Opec output through to the end of 2017 – and perhaps beyond. The Paris-based International Energy Agency forecasts that 4.1m barrels a day will be added to the global oil supply between 2015 and 2021, down sharply from growth of 11m barrels a day between 2009 and 2015.

Saudi spare capacity on the wane

And it’s worth remembering that amidst all the warnings of a prolonged slump in energy prices, Saudi Arabia’s spare capacity has been contracting regardless of the glut in world oil markets. If needs be, the Desert Kingdom could add around 1.1m barrels to daily production, according to analysis from Rystad Energy – roughly half the available output from the ‘swing producer’ six years ago. This alone suggests that oil markets are actually becoming more vulnerable to sudden disruption. That might seem an odd claim with Brent crude futures bobbing around the $38 mark, but market dynamics dictate that once capital has been redeployed in oil markets it’s not easy to turn the taps back on.

Although it’s true that shale producers, at least those still in business, enjoy greater operational flexibility, and are thus able to curtail and re-start drilling with relatively little disruption, it’s also true that a significant proportion of the lost production relates to long-dated conventional projects. That can’t be restored overnight. So short of a major global recession, it seems likely that at some point we’ll experience a lagged effect going in the other direction. The only uncertainties may be linked to duration and severity.

Mini-rally not supported by inventories

There has been a great deal of debate as to whether the recent mini-rally in crude prices is likely to be a temporary effect or whether it heralds a sustained recovery. Although we argue that market fundamentals are much tighter than many commentators would have us believe, the sheer volume of global inventories and the relative resilience of US shale production will dampen prices for some time to come. Even if prices chug along at $40-$45 a barrel through the second quarter, it is likely to draw some marginal US shale production back into the market (finance allowing). But if the underlying glut is still in evidence, expectations of a sustained pricing recovery would be likely to exacerbate the issue over the long run and send prices spiralling downwards again.

Surviving the slump

With crude prices either in downtrend or flat-lining for the best part of two years the impact of the fall-away was always likely to move beyond station forecourts and on to the balance sheets of energy companies. And so it has proved. Industry-wide write-downs have eaten into reserve valuations, while cash flows dried up as crude prices contracted by two-thirds over a 20-month period. Once it became apparent that Opec, or more specifically Saudi Arabia, had no intention of reducing production quotas, producers pared back capital expenditure and rushed to institute favourable hedging arrangements.

For many producers the duration and severity of the oil price slump has undermined their ability to fund existing dividend levels and many are effectively in the process of shrinking their operations, hiving off marginal non-core operations and laying off ancillary staff in record numbers. For many explorers, however, it represents nothing short of an existential crisis. This may become all too obvious in coming months, as production hedges are fast evaporating and borrowers without existing credit facilities are increasingly shunned by banks.

Some believe that the extent of borrowing across the sector, while not comparable in scale to the sub-prime unwinding, should still be viewed as a systemic risk to the banking sector. The amount of bond debt owed by junk-rated energy producers expanded 11-fold to $113bn in the 10 years to 2014, according to analysis from Barclays. Fadel Gheit, senior oil and gas analyst at Oppenheimer & Co, recently said that up to half of US shale producers could go belly up before crude markets rebalance.

The truth is that no one can be sure of the extent to which unconventional oil and gas production in North America will contract if banks pursue margin calls. What we do know, however, is that the glut in global crude markets has forced out a huge amount of long-dated conventional projects. Unlike shale, that can’t be reinstated in short order. As much as 20bn barrels in future production has either been deferred or cancelled outright. This not only translates into falling industry inventories, but eventually the failure to adequately replenish reserves will have a deleterious effect on industry valuations – an unvirtuous circle in the making.

An opportunity

So if we buy into the theory that crude markets may well rapidly tip into deficit, surely this will present highly profitable opportunities for energy companies that make it through the other end. This Darwinian logic obviously calls for a number of prerequisites: strong management; a proven ability to generate positive returns through the entire cycle; an ability to readily increase production in a low price climate; favourable outcomes in terms of debt/liquidity; balance sheets that aren’t excessively leveraged; a track record of generating attractive and sustainable free cash flows; and potential to outperform the sector if (indeed when) Brent crude moves back towards $60 a barrel.

The Survivors

Several oil majors share a common challenge. Since the slump began, all have made concerted efforts to shore up cash flows, while cutting or delaying investments designed to guarantee future revenue streams. That behaviour cannot continue indefinitely, as the value of any natural resources company is dependent on its reserves. Nowhere has this been more apparent than at BP (BP.). Last year, its reserves replenishment ratio – its spare proved reserves relative to the amount of oil and gas produced – stood at a mere 61 per cent. At the same time, the super-major has made a steadfast commitment to protect dividend payments, even as its debt pile increases.

Since the downturn, shareholder returns have been ably covered with operating cash flow, which in 2015 stood at an impressive $19.1bn, or just under three times the dividend outlay. But while the payout has increased by 14 per cent in the past two years, the equity has narrowed sharply from $130bn to $98.4bn.

So why is BP playing this high-stakes game? The first answer is that the group has appeared wedded to accelerating shareholder returns since missing two quarters in the wake of the Deepwater Horizon crisis. The second is that BP’s modelling is based on $60-a-barrel oil this year, almost double the EIA’s 2016 outlook. That seems optimistic. BP can always sell more assets or borrow more to keep up payments, although current energy prices mean that the shares are likely to dilute further, further diminishing the sustainability of the dividend.

Investors can therefore read one of two things into BP’s 7 per cent forward yield: the shares are either at an historic bargain, or the market thinks some portion of the dividend will have to go. Despite making strenuous efforts to restructure and manage costs, and its defensive downstream business, the oil major’s stubborn refusal to go the way of Anadarko, ConocoPhillips and the largest miners and cut its pay out is a bigger gamble than its peers. Accordingly, we have our reservations about the yield, the share price and the buy case.

On the surface, Royal Dutch Shell (RDSB) shares many of BP’s properties as a stock. The Anglo-Dutch giant is resolutely focused on paying its dividend, which comes with a 7 per cent yield, its average reserves replacement ratio has been hammered since the downturn, and it has cut operating and capital budgets. Its refining assets have provided some protection to earnings, accounting for 91 per cent of adjusted CCS profits of $10.7bn in 2015. And, like BP, low oil prices have squeezed cash flow and eroded dividend cover. In a recent interview with the IC’s personal finance editor Leonora Walters, star fund manager Neil Woodford singled out the two oil firms, alongside HSBC (HSBA), as blue-chips with unsustainable yields.

However, several elements give us greater confidence in Shell’s future. Firstly, the equity – which at the end of 2015 stood at $164bn – has pared back at a slower rate than BP’s and is proportionally greater than its net debt. At current crude prices, Shell cannot indefinitely maintain last year’s level of capital expenditure while making dividend payments at or above $9.4bn. In fact, operating cash flow barely covered capital expenses in 2015, meaning Shell had to borrow in order to simply hold dividends at 2014 levels. One answer to this dilemma: sell $30bn of assets in the next three years to build liquidity.

Its cash pile is already fairly strong. As of December 2015, Shell had $31.8bn on its balance sheet, which on its own could ensure the dividend is maintained well past a rebalancing of oil prices. As for asset sales, navigating what is likely to be a buyer’s market will be difficult, but a number of large growth projects due between now and 2020, and extra output from the assets acquired in the BG deal, should compensate for lost reserves. Of the two UK-listed oil dividend giants, our pick is Shell, at 1,739p.

Given the size of BP and Shell – and many of the apparent similarities between the global super majors – UK-based investors could be forgiven for ignoring stocks across the pond. However, ExxonMobil (US:XOM) is certainly worth a look. That’s because the Texas-headquartered producer is the largest listed oil group in the world, with a market capitalisation of $342bn and net debt of just $35bn. Incredibly, its diversified business model has kept it profitable despite the downturn; in the fourth quarter of 2015, Exxon managed to generate earnings per share of 67¢. That’s all the more impressive given Exxon’s policy not to hedge production.

It is also probably the least likely of any oil company to cut its dividend. That’s due to four key factors: its unblemished track record of increasing payouts, low gearing, enormous asset base and free cash flow. In 2015, the latter was well supported by its downstream and chemical divisions, which have a higher return on capital employed than any of the super-majors over the past five years. The group also returned $15.1bn to shareholders through a mixture of dividends and buybacks. That was more than double free cash flow of $6.5bn and required an increase in borrowing, but ExxonMobil’s low gearing should give it a lot of headroom.

That was clearly demonstrated last month, when Exxon tapped the bond market for $12bn, its largest ever note issuance. As the super-major is one of only three US companies with a triple-A rating for Standard & Poor’s, it can borrow at lower rates than any other oil major (and many developed countries). The bond issue was all the more interesting, as it should give Exxon a war chest to buy struggling companies and assets at knockdown prices. In the long-term, such a strategy is likely to be very value-accretive as the supply-demand imbalance recedes, so we rate the company a good buy-and-hold stock.

Though dwarfed in size by a number of industry peers, Hess Corp (US: HES) has a number of highly promising new projects in the offing, ample liquidity and a proven ability to find additional resources. It operates a largely integrated business, involved in upstream exploration and production, along with a midstream refining segment. Hess markets value-added products as well as natural gas and electricity, which are marketed to customers throughout the East Coast of the United States. In 2014, Hess sold its petrol station network to Marathon Petroleum in order to focus on exploration and production, reducing its headcount by half in the process. The group (formerly Amerada Hess) is actually one of the most efficient shale operators in North America and recently reiterated plans to bring around 80 North Dakota oil wells online this year despite the decline in crude prices. At $52.53, the group is currently trading in line with consensus analyst price target, although technical analysis suggests a near-term retracement towards the 12-month high of $79 a share.

Valuations in the oil services sector, in an inverted take on the old picks ‘n’ shovels argument, have been mauled by the oil price slump, but that has thrown up some compelling value plays over the long haul. Amec Foster Wheeler (AMFW), a multi-discipline engineer with high exposure to energy markets, has suffered disproportionately at the hands of traders, due, in the main, to the market’s concerns with borrowing levels. Those worries prompted substantive debt refinancing measures and a substantial cut in the dividend pay rate. The group got on board with a syndicate of 20 banks, including a three-year £650m term loan, a five-year £650m term loan and a five-year £400m revolving credit facility – that should allay any concerns over medium-term funding.

However, orders also fell back slightly in the period from July to October, despite a number of new deals being struck, including a training contract for the UK’s nuclear safety authority and one linked to radioactive waste management at the Fukushima complex in Japan. Something had to give – Amec’s long-standing chief executive, Samir Brihko, who forced through the “transformational acquisition” of LNG and shale-gas-focused services and equipment provider Foster Wheeler, quit the post at the beginning of this year.

The group is firmly in remedial mode. Management has identified a number of non-core assets that it plans to hive off over the next 15 months, in addition to reducing net debt by half over this time frame. We feel this is a quality operator brought low largely by circumstance and its shares now trade at a massive – some might say unwarranted – discount to the sector, a troubled sector at that. With a yield hovering around the 6.2 per cent mark and an implied upside of 96 per cent based on its historic earnings premium relative to the sector, we see Amec Foster Wheeler as a prime recovery play.

We’ve regularly highlighted the defensive qualities of Gulf Marine Services (GMS) in the face of tanking oil services markets. The company specialises in self-propelled, self-elevating support vessels (SESV), built and maintained at a complex in Abu Dhabi, with operations overseen through offices in Abu Dhabi, Saudi Arabia and the UK.

GMS has been insulated against the worst effects of the industry downturn through two principal factors. Firstly, the proximity of the company’s fleet to the Gulf of Arabia is critical. That has also meant that a high proportion of its contracted work is with national oil companies (NOCs) in the region. Gulf’s long-standing relationships with the likes of Saudi Aramco, Dubai Petroleum, and ADNOC provide relative stability. NOCs’ contracts are linked to operating – as opposed to capital – spending, which makes for comparatively predictable revenues and high utilisation rates. GMS obviously isn’t totally immune to the problems besetting the industry; the consequent margin squeeze means that the company expects cash profits in 2016 to be 15-20 per cent lower than in 2015 and EPS (reflecting the increased depreciation charge for the enlarged fleet) to be approximately 25 to 30 per cent lower. In a sense, the margin squeeze was wholly predictable, but it has weighed on the share price, resulting in a lowly forward rating. With the bulk of its contracts linked to predictable maintenance ‘brownfield’ work, we think the shares have been totally oversold.

Faroe Petroleum (FPM) may have recently drawn a blank on the Kvalross exploration well in the Barents Sea, but the independent is particularly well-placed to profit when oil prices finally stage a sustained recovery from current depressed levels. With net cash accounting for about 52 per cent of current market cap and in possession of cash-generative North Sea operations, Faroe isn’t encumbered by undue financial risk and is well placed to invest in its business while oil prices are low. At the half-year mark, Faroe increased the lower end of its 2015 production guidance while operating costs fell to a lowly $22 per barrel. Another inherent advantage is that Norwegian waters are home to its producing and exploration assets. Norway’s highly advantageous tax regime also gives Faroe a clear advantage over UK rivals located on the UK Continental Shelf.

Bowleven (BLVN) – the sole oil and gas services pick in Simon Thompson’s 2016 Bargain Shares portfolio – is also at the junior end of the market, but unlike many of its peers has a balance sheet that should be sturdy enough to deal with a continuation of the oil price slump. A year ago, the company booked $170m (£119m) in cash following the sale of a 40 per cent interest in its Etinde discovery to Lukoil and New Age. The terms of the deal, which still leaves Bowleven with a 20 per cent non-operated stake, should result in a further $15m payment this year and another $25m when the buyers reach a final investment decision on the development. What’s more, the group is carried up to $40m for two appraisal drilling wells and has $304m in exploration assets.

Investors get all of that for free however, as at 24p the company still trades at a discount to the $120m cash it had on its balance sheet at the end of October. Clearly, its remaining Etinde stake is clearly worth millions, as Lukoil and New Age spent $250m for their 40 per cent share. Such is the depressed sentiment in junior explorers that the market hasn’t fully woken up to Bowleven’s valuation anomaly.