Lower prices, tightening climate regulations, a lack of credit – oil firms face an increasingly challenging investment climate.

By-Beth Mitchell*The outlook for international oil and gas investment is being transformed by recent price volatility and the potential for low prices longer-term, a tough financial environment and the impending strengthening of policy to mitigate climate change.

Between June 2014 and January 2015, Brent crude prices plunged by 60%, from $115/B to $45/B, causing a raft of announcements by international oil companies (IOCs) of capex cuts and project deferrals. Although prices have since rebounded to around $58/B for Brent and $52/B for WTI, these are still levels at which there is a significant mismatch between spending plans put in place before the price fell, and those appropriate for these levels, if they do persist.

Industry consultants Wood MacKenzie estimate that IOCs have cut capex by around 20% for 2015 and that this level of cuts implies an expectation of an $80/B equilibrium oil price. For a $60/B equilibrium price, cuts of 35-40% would be needed. The relatively modest spending cuts so far implemented by majors seem less and less justified as the months roll on and prices remain around or below $60/B. They also belie statements from a number of companies including Total and BP that they view the current market phase as a multi-year environment.

Without Saudi Arabia or Opec acting to balance demand and supply – indeed both have increased output (see p10) – the imbalance between growing supply and sluggish demand could well remain in place for many years; after the 1986 price collapse prices remained low and volatile until 2003 when the excess capacity was used up.


The IEA estimates global surplus oil production capacity at 3.5mn b/d in 2014, rising to 4.6mn b/d by 2019, thus continuing to pressure prices. There is much discussion about what price is needed to incentivize sufficient investment in production capacity to fulfill demand. While there is still an industry narrative that states that oil prices must be higher (perhaps over $80/B) for this to happen, recent analysis by Citigroup suggests a long term marginal price of $65-75/B; to 2022 projects needing prices below $70/B (absent disruptions and one off events) are sufficient. The futures curve for Brent only tops $70/B in 2019 and $71/B in 2020. For WTI it does not get over $65/B until December 2019.

Of course global economic growth is a key determinant of the outlook for oil demand (the long term growth rate of China remains crucial). To this must be added uncertainty of future climate policy. This December’s Paris climate negotiations are unlikely to yield targets sufficient to prevent dangerous rises in global temperature, but the resulting framework is likely to open the way for stronger national policies. Almost all such policies aim to reduce the demand for fossil fuels: whether through regulation (so called proxy carbon taxes, ie costs imposed on consumption) or through direct carbon taxes. Such measures result in a wedge between the cost to consumers and the price producers receive, so prices can be low (for producers) without spurring demand.

The IEA estimates that “strong policies” consistent with limiting concentrations of CO2 in the atmosphere to 450 parts per million would reduce investment required by 2050 in the gas, oil and coal sectors by about 15%, 20% and 33% respectively. Similar investment would be needed in renewables, biofuels and (the largest category) efficiency to enable consumption of fossil fuels to fall as intended.

Oil companies are sometimes criticized for not themselves making the switch out of oil and into alternatives. However the alternatives are different industries with different business models: oil companies are reluctant to abandon what they know. The preferred option, as illustrated by ExxonMobil, is to return money to shareholders and let the financial markets take the risks and make choices of low carbon supply diversification.

On the supply side, even with the recent fall in prices, the EIA still forecasts that US shale output will continue to grow until 2020 and then only plateau. This adds sufficient capacity in the middle of the supply curve (around $60/B, and falling as costs fall and productivity rises) to cause a reassessment of whether other resources can be viable under these new circumstances. Although it is not impossible that Saudi policy might change in the future, the existence and scale of US shale cannot be un-invented.

Thus the coming years will be extremely challenging for an industry whose planning assumptions until recently included demand rising while oil became ever-more scarce. This led to many projects being sanctioned or planned that will never be viable at prices of $65-75/B and below. While some can be delayed or cancelled, many others are already producing or at an advanced stage of development: unless prices fall lower and stay there for years they will enter or continue production with the companies taking impairment charges. This will have two effects: these projects will crowd out others that would have been viable at lower prices, whilst the write-downs will add to the disillusionment of financial investors.

Even before the precipitous fall in oil prices, investors were unenthusiastic about the sector given the absence of growth (outside US shale) and poor returns given delays and cost overruns. Host governments’ demands for tougher terms pushed the quoted sector towards high risk areas such as oil sands, the Arctic and ultra-deepwater.

At the same time, the financial sector was changing, or being changed, in the aftermath of the financial crisis. Tighter regulation (eg Basel III) requires banks to hold more capital against loans, whilst banks themselves are pushing to de-risk their loan book. Some banks have reduced their exposure to the oil and gas sector; others have axed their specialist teams altogether, while restrictions on banks’ proprietary trading (the Volker rule) have make hedging more difficult. These developments would have been problematic for the oil and gas sector even at higher prices. New, more lightly-regulated, sources of funding have emerged: private equity, sovereign wealth funds, large pension funds and insurance companies. But their durability as a source of funding has yet to be tested by a prolonged downturn.

The sector has also benefitted from the seemingly insatiable demand for bonds: many companies that would previously have been dependent on a combination of bank loans and equity now are able to access bond finance. This demand has come about as very low interest rates have reduced yields on low risk investments, driving investors up the risk curve in search of yield. But any reliance on such funding is threatened by the eventual unwinding of quantitative easing (QE) in the US and Europe. Interest rates rise will rise eventually, and when they do investors will be able to find attractive yields on lower risk bonds. This may well lead to a massive switch out of bonds into equities, making it much more difficult and expensive for ‘riskier’ oil firms to raise bond finance.

A sub-sector unable to use bond finance or access bank loans is small oil firms that focus on early stage exploration and appraisal. These have traditionally, and aptly, been funded by equity (risk capital, with no fixed payments). Although a number of companies raised funding this way in the high price era, disappointing returns (or over optimistic expectations) combined with consolidation on the part of investment institutions led to a “buyers strike” with new equity almost impossible to raise. Although these are typically small companies, their existence contributes to the overall health and functioning of the oil and gas ecosystem. Many blocks of acreage not large enough to appeal to the IOCs or larger independents, even if viable at low oil prices, will thus fail to attract funding and lie fallow, to the detriment of the national oil companies (NOCs) trying to license them, and potentially of larger companies that might have later bought successful developments.

Small companies, including small NOCs from emerging or would-be producing countries are likely to be most at risk in the lower oil price environment, as they are more likely to have a concentrated portfolio, maybe just one asset which may not be viable at lower price levels. Many small private sector companies will not be able to survive, if oil prices remain in the $65-75/B range and will abandon more expensive acreage. There may be some potential for NOCs to reconsider their terms, but the gap may be too large. The small early-stage NOCs will depend on government funding (some have downstream assets which will keep them afloat) and will need to stay lean or downsize.

Those NOCs and private sector firms that have production have more options: bank loans, reserve-based lending and forward sales. There have been some recent cases of service firms deferring their bills in return for contracts (thus sharing some risk). But despite producing, these oil companies are also hit by lower oil prices and may have to take impairment charges on existing projects, thus reducing their borrowing capacity. Private equity firms prefer companies with production (ie cashflow and the potential for a leveraged sale), so are potential buyers of ‘good assets’ in this category. But several private equity firms feel they have already been stung, having bought assets at much higher levels and had to take large write downs. It is possible that asset prices have to fall further before significant private equity buying takes place. The same applies to oil traders such as Glencore and Marubeni who have invested both in oil production and advanced purchases (again at higher level, with the inevitable write-downs).

US shale has been one of the few upstream areas to attract significant investor interest in recent years. With strong growth prospects, relatively straightforward regime risk and access to the deep and specialized US financial markets, shale was both able to grow prior to the oil price collapse and to be surprisingly resilient afterwards. A combination of reserve-based lending, high yield bonds (for which a large specialist market exists in the US) and some equity issuance in early 2015 means that although rig counts have fallen to 40% of peak numbers, production is still up year-on-year and a number of operators are starting to add rigs again. Although detractors focus on the very high annual depletion rates (65% is common) and the need to keep drilling, for a financial investor the unit cost is small and the payback very fast relative to any other kind of oil investment (18-24 month payback versus more than a decade for LNG). The price fall has accelerated the maturing of the shale industry with “mom and pop” operators squeezed out by the better run, better financed companies able to access good acreage and take advantage of lower costs.

IOCs have had their ability to fund projects from cash flow severely curtailed and have looked to cut costs, better target investments and sell assets (though there is a shortage of buyers). The majors (Exxon, Chevron, Shell, Total and BP), who are better funded, have opportunities to strengthen their portfolios by buying high quality assets that position them better on the cost curve (as the Santos Basin does for Shell).

NOCs’ access to finance is determined by the extent of their financial independence from their national governments and the degree to which their national economies are diversified. Saudi Aramco and Adnoc are relatively insulated because their governments built up substantial fiscal and foreign-exchange reserves, even as domestic spending and imports increased. Part-private NOCs, like Petrobras and especially Statoil, are shielded from government, but not from the fluctuating confidence of financial markets. The problematic ones are Venezuela’s PdVSA (though quite adroit financially, national politics impede its efforts), Iran’s NIOC, Nigeria’s NNPC, Kazakhstan’s KMG and others, who cannot insulate their finances from government.

NOCs looking for external investment will need to consider whether they can improve the terms they offer to attract investment. Governments in such countries will also have to temper their spending plans in light of reduced revenue expectations.


NOCs will need to be smarter with their spending. Spending on training, local content, development of operator capabilities, and acquisitions needs to be closely directed by company strategy and its results carefully evaluated. Where this spending is out of line with available geological or financial resources, ambitions will have to be reined in. The lower price environment is an opportunity to increase efficiency across NOCs and refocus their mandates to fulfill their government’s energy vision.

Overall, those firms, whether national or private, with cash or access to funding will be able to take advantage of much lower project costs and potentially better terms. They will be able to extract good assets from badly financed companies. If oil prices remain subdued for a long period, the sector will not expand and may become smaller, but investors could be rewarded by more focused managements undertaking more realistic projects with better returns. The more companies restrict investment to realistic projects, the more likely that supply and demand will return to equilibrium. History suggests that as the sector retrenches, excess capital should be returned to shareholders and reallocated through the financial markets: for oil companies diversification into renewables – or anything else – is unlikely to turn out well.

The more clearly governments outline their climate change policy plans, the more clarity companies (state and private) can have about the likely trajectory of demand growth, and the less likely they are to make investments in unnecessary projects. If the policy pathway is unclear there is a “Janus risk”: weak policies leading to higher fossil fuel demand requiring higher investment (or leading to much higher prices) or policies unexpectedly become stronger, leaving investments in projects no longer needed (“stranded”) and redundant.

The financial sector should not fund projects or companies that are not viable at lower oil prices. But it has the challenge of finding ways of funding companies, for example early stage exploration and appraisal that have an important role in the ecosystem of the sector.