With a lower for longer oil price prediction, and mounting concerns regarding the potential cost of decommissioning, striking deals in the upstream market remains extremely challenging, yet possible.
We are increasingly seeing a willingness to embrace a more creative approach in the market, with businesses closing the value gap through deal structure, risk sharing, and even creating new ventures to solve the funding gap.
At the moment, it appears that the chances of unlocking the traditional Mining and Acquisitions (M&A) cycle remain a long way off; however it is not that there is a lack of appetite for investment, but rather how difficult it is to strike a deal. This is mainly due to lingering pessimism amongst the sector, cost pressures or the immediate cash cost of delivering DSAs.
Financial pressures are also at play, with funders still trying to adopt a restructuring model, manage the downsides, seek security and returns that are extremely difficult to deliver alongside existing capital structures.
Grounds for optimism
The ingredients are in place to unlock investment with private equity, banks and funds – and the odd strategic investor – engaging in conversations at the deal table.
The challenge early in the year was that, with some notable exceptions, a lot of the teams backing this new money were relatively inexperienced in oil and gas – they had the investment and structuring sophistication, and the ability to put structures to work that help them to manage risks in an environment like today’s, but had yet to apply this to the North Sea. The good news, however, is that the sophistication around this new money is maturing fast, driven by the number of deals they have worked on so far, and their engagement with management and technical teams. They are therefore now actively developing structures, including high degrees of debt, that offer adequate return for the risk. This is a key factor in unlocking many of the stalled deals across the sector.
The way the market is valuing oil field services businesses is creating a seller buyer price expectation gap, resulting in a hiatus in deal completions over the past 12 months. Forecasts are hard to make in a volatile market but there are clear drivers, and themes emerging.
In order to free up this M&A gridlock, more creative solutions need to be found. This includes:
More risk sharing between the buyer and seller, across the capital structure, and across stakeholders.
A clearer distinction between production and pre-production risk and reward for asset backed lending.
Looking to the supply chain as a source of investment.
Innovation against this challenging backdrop is key. One solution that is increasingly being used when trying to get a deal away is to bring in supply chain funding. This is a far lower risk approach and a more cost effective source of capital and it is really working well.
Opportunities in Adversity-Strategies for a Lower Oil Price
The 60% collapse in the oil price that had occurred since July 2014 raised many viewpoints of Opportunities in Adversity. At the time, there was no clear consensus about what shape the price recovery would take. In the past, the price has sometimes rebounded quickly, for example after the 2008-09 collapse, but at other times has stayed depressed for a prolonged period, such as after 1986. We believe that this second scenario, of the oil price staying lower for longer, is the most likely at present given the current and anticipated future supply glut in the market. In this paper we take a critical look at what this means for the sector and focus on two key imperatives to success in a prolonged low oil price environment: Developing a business strategy truly driven by a company’s capabilities, and “Right-sizing” the cost base to sustainably deliver the chosen strategy.
Market Developments and Oil Price Outlook
Over the past six months, the oil market has been on a rollercoaster ride. By May 2015, the oil price had recovered by almost 50% from its lowest point in January, but this turned out to be a “false dawn” for those hoping for a quick recovery. In August it dipped towards the $40 mark and, at the time of writing, remains below $50.
Gas prices have followed the trajectory of the oil price, albeit with a lag in the case of LNG and to some extent European markets. However, the proportionately less severe drop has been partly due to the more fragmented and regionalized nature of the market and longer-term contracts for LNG and natural gas in Europe. Nevertheless, the gas market as a whole, and LNG in particular, continues to be oversupplied and prices are likely to remain weak.
The same is true of the oil market where factors such as the so far relatively resilient shale oil production, the medium term potential for increased cheap supply from Iran and the slowdown in China and other emerging markets suggest that the price is likely to stay ‘lower for longer’ – even if remaining highly volatile.
OPEC’s decision to maintain production at 30m bbl/day has not curbed production elsewhere, with US shale-oil production proving far more resilient than OPEC had expected. While the US rig count has more than halved in the past 12 months, oil output from seven key US regions was up 10% year-on-year in August 2015. The picture is similar for US natural gas production. Such results have been achieved with deeper, more productive wells that go further horizontally, while fracking equipment and products have also decreased in cost.
With renewed pressure on the oil price, the resilience of US production will continue to be challenged – not least because many independent shale oil producers have weakening balance sheets and debt overhang. Nevertheless, non-completed shale wells have also risen in number and can act as natural storage. This, together with shorter exploration-to-production times, allows far quicker responses to market developments than conventional oil producers can manage.
Other non-OPEC production has been similarly resilient, with Russia producing above Saudi Arabia’s output of 10.6m bbl/day in July and August 2015 to make up for the revenue shortfall from the lower price. Furthermore, around 600,000 – 800,000 bbl/day could be released onto the market in short lead-time throughout 2016/17 in response to an uplift of sanctions on Iran. The two big questions regarding Iran are:
How quickly can Iran increase its production by up to 1.2m bbl/day to realize its production capacity target of 5m bbl/day given the need for foreign investment in infrastructure? How will fellow OPEC countries respond as new Iranian supply will exert additional downward price pressure?
As the world’s second largest oil importer after the US, China is crucial. As early as this year, Chinese annual economic growth is expected to moderate below 7% due to slowing capital investment and a gradual shift from energy heavy industries. The growth could eventually fall below 4% by 20203, with obvious implications for oil demand. The EIA expects China’s oil consumption to grow around 300,000 bbl/day in 2015 and 2016; 100,000 bbl/day lower than in 2014 and far below the 2009 – 2011 average of 800,000 bbl/day.
China’s dependence on energy imports and its slowdown also negatively impact commodity-exporting emerging markets such as Russia, Brazil, Indonesia, South Africa and the Gulf countries.
The scale of the actual and anticipated supply growth has not been mirrored by demand. The US Energy Information Administration (EIA) recently downgraded its forecast for growth in global oil demand in 2016 by 0.2m bbl/day to 1.3m bbl/day. This was largely due to ongoing signs of weakness in China and other Asian economies. As a result, we can clearly see why the outlook for both supply and demand has led analysts to conclude that a low oil price will recover over the medium term – as evident from the futures market. However, the future price trajectory remains uncertain due to financial market adjustments on the demand side, following an eventual tightening of US monetary policy, declining growth rate of emerging markets, the Eurozone debt crisis, and the ongoing unrest in the Middle East.
Growing anticipation of an important deal on climate change at the UN meeting in Paris this December provides an additional source of uncertainty. Oil majors called for a cross-border carbon pricing system earlier this year, but a range of other policy responses are possible.
In summary, the “false dawn” for oil prices was short-lived and the industry must recognize the very real prospect of a ‘lower for longer’ scenario and adjust accordingly.
Industry response to date
Oil and gas markets are inherently cyclical. Hedging physically or financially, cutting costs and raising new finances are popular ways to ‘smooth’ cash-flows through periods of volatility.
Oil majors, which operate across the entire value chain, can hedge against some of the fall in upstream revenues with increased margins in refining and downstream retail business. The performance of US-based refineries is a particularly good example of this. Furthermore, companies with trading arms can find further advantages in market volatility.
The development of financial instruments, such as energy futures and options, has also enabled smaller players without operations across the value chain to hedge a portion of their production. The Bloomberg Intelligence North America Exploration and Production Index found that payments from hedges accounted for at least 15% of Q1 2015 revenue for nearly half the 62 US oil players they follow.
Faced with declining revenues and uncertainty about the future market direction, IOCs have so far concentrated on predictable, tactical efforts to reduce costs, rather than strategic changes. Most E&P companies, with a few notable exceptions, have focused on ‘low hanging fruit’ across three main baskets – planned CAPEX, contractors and workforce size and remuneration. These interventions reduce a business’s scale and scope, but do not fundamentally alter ways of working or the underlying cost structure.
The capital intensity of exploration means future CAPEX projects are almost always one of the first costs to be reviewed. Compared to 2014, IOC cut their global E&P CAPEX by over 25% in 20156. Estimates suggest that up to $200bn worth of long-term capital projects have been deferred or cancelled. These projects have largely relied on a higher oil break-even point, and lie towards the right of the supply cost curve. Oil sands in Canada and deep-water projects have been the biggest targets for this reduction.
Debt issuance for industry companies in Q1 2015 was the highest recorded since at least 2009. We looked at debt issuance since the oil price started to decline in July 2014 by 66 integrated and E&P focused O&G companies with a combined market capitalization of over $1.6 trillion. Our sample alone has raised $150bn of debt between August 2014 and July 2015 – almost two thirds of it since February 2015, and more debt has been placed on the market at the time of writing this piece.
In some cases, oil majors with good credit ratings used new debt to maintain their capital expenditure, dividend payments and gather ‘dry powder’ for potential acquisitions. Loose monetary policy across advanced economies also means that debt offers very competitive rates of financing compared with previous oil price periods.
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DR. AHMED RASHWAN
PwC Director- Head of Oil & Gas
PwC Partner- Utility, Mining & Energy Leader
PwC Partner-Assurance Leader
PwC Director, Industry Expert