IEA (2020), World Energy Investment 2020, IEA, Paris https://www.iea.org/reports/world-energy-investment-2020
Only a few years after the major cuts seen in 2015 and 2016, investment in the oil and gas sector was hit with an even greater shock in 2020. Markets, companies and entire economies reeled from the effects of the global crisis caused by the Covid-19 pandemic, and the impacts were felt all along the global hydrocarbon supply chains.
Oil markets were hit particularly hard. The industry had to react to precipitous declines in oil demand and prices as the pandemic slashed fuel use in the transport sector, aggravated in the early months of the year by the removal of restraints on supply from the OPEC+ grouping.
Consumers in lockdown cannot take advantage of lower prices, so a traditional stabilising element in markets was missing. Instead, the task of balancing the market in 2020 fell almost entirely on the supply side. The dramatic extent of the second-quarter declines in oil consumption were well in excess of the industry’s near-term capacity to adapt, even with the output deal eventually agreed by OPEC+ in April.
The crisis has forced some existing production to halt, in part because the economics do not support continued operation but also because a rapid build-up of oil stocks saturated available storage capacity in some parts of the world, even leading to negative prices at times. For some producers, there was simply no place for their oil to go.
Natural gas prices (already low before the crisis) and consumption have also been affected by lockdowns, although not to the same extent as oil. But oversupplied gas markets are likewise showing signs of strain and these pressures could intensify later in the year as gas storage facilities, already at record highs, fill up even further.
Companies have responded with sharp downward revisions to their 2020 investment. The initial reductions in capital expenditure average around 25% compared with the plans that had previously been outlined for the year. In our view, given continued financial stress, practical difficulties with project implementation and some disruption to supply chains, the likely net result for the global upstream sector is a drop of almost one-third in investment compared with 2019.
Following the previous oil price fall in 2014, the effect of cuts in capital expenditure were mitigated in practice by declines in upstream costs. As a result, the 40% reduction in nominal spending from 2014 to 2019 turns into a much smaller 12% reduction in upstream activity. However, the scope for further cost reductions today is much more limited, because much of the efficiency gains have already been harvested. As a result, today’s declines in investment are translating more directly into reductions in activity.
The cutbacks and financial stress are especially stark among some independent US companies and shale producers, many of which were already facing demands from investors to shore up business models and improve cash flow before the recent price crash. Some producers – of shale and other resources – have hedged a portion of 2020 output at higher prices, but this protection rarely extends far into the future, and the design of some existing hedges has not provided much of a shield in these extreme market conditions.
Reductions in upstream activity have meant renewed strain on the companies that provide services and supplies to the oil and gas industry. This has been reflected in multiple announcements of layoffs.
Alongside the sharp cuts in capital expenditure, the crisis has also had practical implications for investment activity by disrupting existing investment projects and the supply chains on which they rely. These effects can be grouped into four broad categories:
- Risks to teams living and working together on existing onshore or offshore projects. Workers on these facilities typically stay in close quarters in camps or on rigs, making social distancing almost impossible. Regular rotations of staff also increase the possibilities for infections to spread. Companies have been trying to mitigate these risks with regular health screenings, by limiting the number of people on site and by extending the stays of those who remain. Even without an outbreak of the infection, the risk-mitigation measures affect the speed at which projects move ahead.
- Restrictions on movement of personnel. Companies rely on national and international mobility to staff their projects and provide services, and this has been severely curtailed. This inevitably creates delays where either the company itself, or the sending or receiving country, has introduced restrictions on travel, especially when a company is looking to start or ramp up investment activity. This has contributed to a raft of announced project delays: for example, Siccar Point Energy delayed its planned sanction date for the Cambo project, located west of Shetland, to 2021 “given the uncertainty of the global situation, including whether any people, goods and services can be mobilised”.
- Supply chain disruptions. Production and delivery of material and machinery for projects have been interrupted in some cases because of lockdowns, either because the factories themselves are affected or because transport (e.g. port facilities) is disrupted. For example, out of a global total of 28 floating production, storage and offloading vessels that were under construction in the first quarter of 2020, 22 were being built at shipyards in China, Korea and Singapore, all countries where industrial activity was severely affected. Likewise, the Lombardy region of Italy, which was among the first areas of Europe to be locked down, is a major manufacturing centre for specialised engineering equipment for the oil and gas industry.
- The current crisis has been an eye-opener for many companies about vulnerabilities in their supply chains: in general, local supply chains have proved beneficial, and this could have implications for investment and procurement strategies in the future.
- Delays in licensing rounds, approvals and permitting processes because of disruptions to the work of the regulatory authorities. Several countries, including Bangladesh, Brazil, India, Liberia, Senegal, South Sudan, Thailand and the United Kingdom, have already changed planned licensing round activities.
Alongside planned reductions in capital expenditure, these practical considerations are delaying start-up or implementation of many projects, representing a further downside risk to spending in 2020 as activity is pushed back into 2021 (or beyond, in some cases). This is why our estimate for upstream spending is lower than what would be suggested only by company announcements.
Companies have a limited number of choices as they adjust their spending to the fall in the oil price. They can delay or shelve planned activities, or they can seek to make their activities less costly via efficiency gains or by pushing contractors to reduce costs (or by reducing their own overheads).
The pressures on companies may appear similar to those that followed the last price fall in 2014‑15, but in practice the cost-cutting options open to companies today are much more constrained. The investment projects that are on the table today are already much leaner and cost-competitive than they were five years ago, having undergone intense screening in the meantime for opportunities to trim excess costs via simplified and standardised project designs.
Likewise, the oilfield services and equipment sector has undergone major streamlining over the last few years and there is much less scope for additional savings this time around. Global upstream costs are expected to drop by around 5% in 2020, largely because of anticipated reductions in engineering and project management costs as well as services, but this is much less than the headline fall in capital expenditure. Costs in the shale industry are expected to come down by a similar amount, mainly due to oversupply of rigs and pumping equipment, lower anticipated labour costs, and inflation.
The patterns of project delays and cost-cutting are visible across all types of company and all regions, but there are some strong variations in the severity of the measures taken. The largest cuts – in many cases above 50% – have been among the independent North American upstream operators, especially those in shale (see next page). Announcements from independent companies outside North America vary quite widely but are generally lower, in the 10-25% range. Announced cuts by the Majors average more than 25%, with ExxonMobil – the Major with by far the largest announced investment spend – making the largest reduction.
There have been fewer formal announcements made by national oil companies (NOCs), but the precipitous declines in hydrocarbon revenue to the companies and their host governments are working their way through into investment plans. Adnoc and its partners have announced the cancellation of major tenders. Saudi Aramco has said that it plans to cut capital expenditure by as much as 25% from 2019’s USD 33 billion.
This appears to be indicative of the overall trend among NOCs: Brazil’s Petrobras and PetroChina have both announced a 30% cut in spending. The retrenchment in some places has been even more severe, for example the 50% fall in investment for Algeria’s Sonatrach. Russian companies are also exposed to the crisis, although investment spending has been supported by a devaluation of the rouble (which effectively means a reduction in dollar-denominated costs) and also by the structure of the tax system, in which the government absorbs most of the hit when oil prices fall.
The latest downturn has been painful across the board, but there are three parts of the industry that are particularly vulnerable. First, medium-sized and smaller companies in North America – often heavily invested in shale – that had been under financial pressure already before the price collapse. Second, weaker NOCs in countries that are heavily reliant on hydrocarbon revenues. And third, the service companies that are bearing the brunt of the cutbacks in capital expenditure.
The shale industry as a whole was struggling to generate significant free cash flow at prices above USD 50/bbl (West Texas Intermediate [WTI]), so it is no surprise that at oil prices of USD 30/bbl or less, the outlook for many highly leveraged shale companies looks bleak. Some are already seeking bankruptcy protection, with Whiting Petroleum being the first of the larger producers to do so, and strains will intensify for a good portion of the sector (see also the Energy Financing and Funding section). We estimate that upstream spending on shale (tight oil and shale gas) is set to decline by 50% year-on-year in 2020.
Unlike in 2014‑16, today there are few prospects for companies to sell upstream assets as a way to service debt or raise capital. The fall in the oil price also means that companies that use reserve-based lending face a significant revision in their value of available debt. This will hit small and medium-sized companies particularly hard (not just in shale). With the possibility of more constrained access to capital in the future, one consequence of the current crisis may well be a consolidation of the industry towards larger players with deeper pockets.
The damage to investor confidence and to available financing will take time to repair, but it is too soon to write off shale. Drilling new wells would naturally require a rebound in prices (for most plays and operators, well into the USD 40s/bbl), but shale has proven its resilience in the past and investment can pick up when market conditions allow. After a wave of bankruptcies, though, it will be a different industry from the one that we have known until now.
Some indebted and poorly performing NOCs are also being hit very hard by the current crisis, with knock-on effects on host governments that rely on oil and gas revenue to provide essential services. The crisis is playing havoc with reform initiatives, such as Angola’s plans to restructure Sonangol and bring in new players to the country’s upstream. The deterioration in asset quality could have ripple effects across the banking sector in countries such as Nigeria. In a worst case, some higher-cost NOCs risk falling into a spiral of lower revenue, investment and lower output, along the disastrous path that Venezuela’s PDVSA has followed in recent years.
Companies providing services and supplies to the oil and gas industry are also facing another very difficult adjustment. Jobs servicing the shale sector are being hardest hit, but the effects would be widely felt across the industry. Petrofac, which operates extensively in the Middle East, is anticipating a “considerable impact” on demand for its services in 2020 and is reducing its own capital expenditure by 40%, alongside a 20% reduction in staff numbers.
In recent years, investment in new refining, petrochemicals and LNG capacity had already started to run ahead of near-term growth in consumption: the effects of the crisis on demand mean that this problem of overcapacity now looms very large. There are clear opportunities in all of these sectors, especially given that longer-term demand expectations for plastics and for gas are relatively robust. However, there are risks as well given that these sectors involve large, capital-intensive investments that require high levels of utilisation over time. Unlike the production declines in the upstream, there is no natural protection against the risk of demand coming in below expectations.
New LNG project announcements had a record year in 2019, even without considering Qatar’s drive to expand its own export capacity. But these plans have now been jolted by lockdowns, weak gas demand, and falling oil and natural gas prices. The selection of contractors and partners for the Qatari projects has been pushed back; planned projects in North America face delays because of both local workforce disruption and the closure of Asian fabrication facilities making modules for the plants; and travel restrictions are preventing work from scaling up on Mozambique’s first onshore project. New project announcements, initially anticipated for 2020, are also being postponed.
A similar dynamic is visible in the petrochemical industry, where a surge of investment over the past few years (also linked in part to the shale revolution) has led to concerns about overcapacity. Prices for chemical products were falling already in 2019, and 2020 has put further pressure on the economics of production facilities. This is likewise triggering a reassessment of the timelines for some of the planned projects that have not yet started construction.
In both LNG and petrochemicals, uncertainty around the trajectory of demand and prices and the shape of an eventual recovery from the economic slowdown are going to weigh heavily on investment decisions. By pushing down prices worldwide, the crisis has also – for a while at least – removed the competitive edge afforded to US exporters by the shale revolution. Spot natural gas prices are hovering around the short-run marginal costs of US LNG exports, and low oil prices are now erasing the traditional cost advantages that US ethane crackers have enjoyed versus their naphtha-based counterparts in Asia and Europe.
Refiners are coming under huge pressure as well. In normal times, low crude oil prices are not necessarily bad news for refiners. However, the plunge in demand really squeezes refinery margins and volumes. Refiners are responding by cutting run rates and accelerating the yield shift from gasoline, which is hardest hit by the lockdowns, to diesel.
The Majors and independent refiners are taking a hard look at planned investments and divestments. Many will re‑evaluate their existing portfolios, possibly leading to another wave of closures as some refineries at the higher end of the cost curve shut down (and then struggle to reopen). This would accelerate the restructuring of the global refining industry towards regions benefiting either from cheaper inputs, such as the Middle East, or close to still-growing demand, such as in developing countries in Asia. The role of NOCs in global refining is likely to strengthen as a result.
Shrinking coal demand, lower prices, environmental pressures and disruptions to supply chains and investment operations are set to bring a substantial decline in coal supply investment in 2020. However, the estimated 15% decline compared with 2019 is not quite as severe as those seen in oil and gas supply.
The main mitigating factor relates to China, which accounts for more than two-thirds of global spending on new coal supply. An expansion in Chinese investment in existing and new mines was the key reason behind a 15% rise in global coal supply investment in 2019. And the gradual resumption of Chinese industrial activity is a key factor limiting our estimated decline in 2020. By early March, more than 80% of China’s coal mining capacity was already operational, and investment in existing and new mines has been on a cyclical upswing after a wave of consolidation and restructuring in 2016‑17.
The recovery in coal demand in China for industry and electricity generation, after a sharp fall in the first quarter, is offsetting in part some profound declines elsewhere. Coal demand in Europe, North America and in some key emerging markets – including India – has fallen because of lower electricity consumption, the low marginal costs (and priority dispatch) of renewables and rock-bottom prices for natural gas. Overall, the IEA estimates that global coal demand could fall by 8% in 2020 – a higher figure than the 5% anticipated drop in electricity consumption.
The lower demand outlook is feeding through to the supply side: after holding up in the first quarter, prices for thermal coal tumbled in April. The impacts have been particularly strong in export-oriented producers, such as Indonesia, where coal supply investments are reported to be well below the USD 7.6 billion target set by the government for the mining sector in 2020. However, this is not yet the case in China and India, where large state-owned companies follow long-term strategies driven by factors such as energy security and local jobs, which are structural considerations beyond the (longer or shorter) effects of Covid-19. Coal India, the dominant producer in India, reported an all-time high production level in March 2020.
The economics of coal supply are helped somewhat by a lower oil price, as oil products represent a significant share of coal mining and transportation costs. The share of oil products in coal operating costs is technology-dependent, but typically ranges from 5-30%, i.e. a drop in oil prices of 30% would translate into a reduction of operating costs between 2-10%.
Low oil prices bring renewed uncertainty to the biofuels sector, where capital investments were already at a decade-long low in 2019. In the absence of strong policy support, the erosion of operating margins may lead to the idling of plants and a further cutback in investment until conditions improve – a trend already visible in the United States. In addition, a low oil price environment may undermine implementation of biofuel mandates and slow movement towards higher blends.
We estimate that investment in new biofuels production capacity will take another hit in 2020, well short of the levels implied by existing policy targets, let alone the amounts that would be required to help meet international climate goals.
The downturn means that significant oil and gas resources that would otherwise have been available to the market in the coming years will not be there. Some of this is deferred, i.e. production that will take longer to come to market. Some of it will not come through at all, either because new projects are simply shelved or because some existing production is shut in due to the crisis and not restarted.
What does this mean for future supply-demand balances and for energy transitions? Already, the decline in investment in 2020 takes an estimated 2.1 mb/d away from anticipated oil supply in 2025, and some 60 billion cubic metres (bcm) off natural gas output. However, if investment were to stay at at 2020 levels for the next five years then this would reduce the previously-expected level of oil supply in 2025 by almost 9 mb/d, and bring down natural gas output in that year by some 240 bcm.
Today’s crisis could also lead to small additional losses (primarily for oil) due to production capacity that is shut-in and not regained. This would arise because of lower productivity from some tight oil wells that are shut in and then re-started, as well as permanent closure of some older, low-productivity fields with relatively high operating costs.
The implications of these reductions in future supply for market balances are highly uncertain, and depend largely on the shape of the economic recovery from the Covid-19 crisis, and the extent to which climate and sustainability concerns are baked into that recovery.
If the recovery is relatively rapid and the world returns to its pre‑crisis demand trajectory, this increases the risk of an eventual tightening of markets. Previous analysis in the IEA World Energy Outlook and WEI already highlighted that investment may be falling short of what would be required in such a scenario. The pickup in conventional project approvals in 2019 (discussed below) appeared to lessen the chances of a supply crunch, but the decline in investment in 2020 has brought this possibility back into focus.
If, however, the recovery is slower or – from a more positive perspective – if efforts to kick-start economies also incorporate policies that accelerate clean energy transitions, then the risks of a future shortfall in oil and gas supply would be significantly lower. Investment in hydrocarbons is still required even in the rapid energy transitions modelled in the SDS, mainly to compensate for declining output at existing fields, but by the latter part of the 2020s upstream spending in the SDS is already a quarter below the levels in the STEPS.
The lasting implications of today’s crisis also depend on the scars that it leaves on the oil and gas industry. A prolonged period of lower prices could provoke a profound industry shake-out, with weaker or higher-cost players forced to the sidelines or out of the business altogether (unless governments are willing to reduce their own take in order to ensure the viability of domestic players). A more concentrated and risk-averse industry could struggle to invest adequately in new supply, given the likelihood of continued fiscal strains in many resource-rich countries and potential investor apathy elsewhere.
From an environmental standpoint, there could be marginal gains from such a shake-out for the industry’s greenhouse gas profile, as some higher-cost resources are also more emissions-intensive. However, this crisis also has the potential to squeeze the funding available for investment by the industry in cleaner energy technologies.
The social and environmental pressures on many oil and gas companies raise complex questions about the role of these fuels in a changing energy economy and the position of these companies in the societies in which they operate. These questions become even more challenging in the revenue-constrained world of 2020.
Many large oil and gas companies have made specific commitments to diversify spending in favour of lower-emissions technologies and reduce their emissions. These commitments vary in scope and ambition, but a notable recent evolution has been for some emissions-reduction pledges to encompass not just a company’s own operations, but also the emissions resulting from the energy that they sell to end consumers, i.e. the combustion emissions from transport fuels, or from gas used for heat or power. BP’s commitment from February 2020 to reduce all emissions from the oil and gas that the company produces to net zero by 2050 is a prominent case in point.
This implies a massive ramp-up for companies in the share of investment that goes to low-emissions energy, whether that is electricity or low-carbon fuels.
So far, investment by oil and gas companies outside their core business areas has been less than 1% of total capital expenditure, with this indicator reaching around 5% for the leading individual companies. The largest outlays have been in solar PV and wind. In addition, some companies have moved into new areas by acquiring existing non‑core businesses, for example in electricity distribution, EV charging and batteries.
Companies that have made strong pledges to diversify spending and support energy transitions will be wary of breaking these commitments. Indeed, the current environment should make returns on some low-carbon investments appear more attractive – especially when adjusted for risks such as oil price volatility (see Energy Financing and Funding section).
Our monitoring suggests that the flow of investment into low-carbon projects by oil and gas companies has continued into 2020. There was almost USD 1 billion in new investment decisions, all in solar PV, announced by subsidiaries of BP, Shell and Total in the first quarter of the year, plus a large onshore wind project from YPF in Argentina. This is an amount equivalent to around half of the total 2019 spending. In addition, Equinor, Shell and Total announced in May a final investment decision on the Northern Lights CCUS project, which will take captured industrial sources of CO2 and inject them in subsea storage in the North Sea.
It is too early to judge whether momentum behind all aspects of company low-carbon strategies can be maintained. A plausible outcome is that cash-constrained companies will be very selective about their spending, with only the very best projects having the chance to move forward. This could favour clean technologies with established business models, such as solar PV and onshore and offshore wind. Progress on projects in low-carbon hydrogen, advanced biofuels or CCUS will depend on supportive policies and public-private collaborations.
Against the pre-crisis backdrop of robust demand growth, the IEA has expressed concern over the implications of a prolonged slump in new conventional oil and gas resource approvals since 2014. In particular in the oil market, these approvals had fallen to levels that relied on continuous rapid growth in US tight oil to pick up the slack and meet rising demand.
In 2019, however, the balance changed somewhat. Overall upstream spending was up by 0.6% in real terms (2% in nominal terms, slightly below the guidance provided by companies to the market). The growth in investment came from conventional projects rather than from shale, which experienced a decline in spending for the first time since 2016 (although not necessarily a decline in output – US tight oil, for example, continued to grow by over 1.2 mb/d).
The volumes of conventional resources subject to FIDs were significantly higher in 2019 in the Middle East and the Americas (for oil), due mainly to deepwater plays in Brazil and Guyana. The same was true for natural gas in the Middle East, the Russian Federation (hereafter, “Russia”) and Africa, in many cases related to the rise in approvals for large LNG projects (see below).
Successive WEI reports have also noted the strategic shift in recent years in favour of smaller, more modular investments with shorter lead times. This was a way to limit upfront capital spending, accelerate paybacks and reduce exposure to long-term risks. However, 2019 saw some much larger projects being approved, chief among them Russia’s Arctic LNG, Mozambique’s Area 1 LNG, and the expansion plans for the huge Berri and Marjan projects in Saudi Arabia. This indicated a renewed degree of comfort within the industry for larger project sizes, albeit while retaining the emphasis on short times to market and for simplified and standardised project designs.
Another development that eased concerns about the adequacy of future supply (until the 2020 shock) was some evidence that decline rates for conventional fields have slowed. This topic was covered in detail in the 2018 World Energy Outlook (IEA, 2018); in this follow-up analysis, to avoid any potential impact of market management policies on field production histories, we focused only on non-OPEC fields that have already fallen below 50% of their peak production.
The five-year average decline rate of these fields (with fields weighted by their cumulative production) suggests that decline rates have dropped by about 0.5 to 1 percentage points in the period since 2015. A key explanation for this drop is that after the oil price fell in 2014, companies focused on getting the most out of their brownfield assets rather than taking on major new projects.
A small fall in decline rates may not seem very significant. However, around 50% of oil production today comes from post‑peak conventional crude oilfields. If we were to assume that a 0.5% reduction in decline rates was a structural change across the board, then by 2025 production from all post‑peak fields would be 1.3 mb/d greater, significantly reducing the amount of investment in new fields that would be required to balance the market. The impact of the 2020 drop in investment on decline rates will require careful monitoring to see if these gains are being maintained.
The allocation of upstream investment spending varies considerably across different types of oil and gas companies. These variations reflect the types of resources to which these companies have access, but also the pressures that different companies feel from investors and societies, as well as different perceptions of future risks.
There has not been any clear change in recent years in the allocation of upstream spending by NOCs; the strategic shift has rather been towards vertical integration strategies via an expansion of investments in refining and petrochemicals (discussed below). Within the upstream, the tendency has been towards internationalisation of some NOC operations led by companies such as Equinor, Gazprom, Petronas and the Chinese NOCs, lately joined by others such as Rosneft and some key companies in the Middle East. The intent has been to seek out new opportunities for growth as well as to acquire new expertise. However, there is no visible shift in aggregate investment towards “frontier” technology areas such as deepwater or shale. The bulk of spending remains in traditional areas of NOC strength, in resources to which these companies typically enjoy preferential access: conventional resources found either onshore or in shallow water.
By contrast, the Majors have undergone a strong shift in their capital spending over the last decade. The precise direction varies by company, but overall there has been a strong move into shale, which now accounts for one-fifth of total spending, up from less than 5% at the time of the last oil price crash in 2014, and out of oil sands. Deepwater investments have retained a prominent place, reflecting investment opportunities in the Gulf of Mexico and offshore Latin America (notably Brazil and Guyana).
The emphasis on technology leadership among the Majors has been accompanied by a preference for projects that combined cost advantages with easily realisable commercial prospects – including short lead times and proximity to existing infrastructure.
The Majors’ investment strategies appear to be designed with future uncertainties and transitions in mind, whereas most NOCs are locked into a more traditional hydrocarbons paradigm. However, although natural gas features prominently in the Majors’ priorities, there are few signs in the combined data of a shift towards upstream gas investments. The share of gas investment in the early years of the decade was boosted by the large investments made in gas to supply LNG export facilities in Australia, but this effect dissipates after 2016.
Independent exploration and production companies headquartered in North America have an even greater exposure to unconventional resource types, mostly shale. This has been a vulnerability in today’s downturn, and this segment has seen the largest revisions to anticipated investment spend in 2020.
Outside North America, though, the allocation of spending by “independents” is more traditional, albeit with a higher share of deep water (thanks to companies such as Galp, Kosmos Energy, and specialised operators across Latin America and Africa), and a higher share of spending on natural gas.
Oil and gas exploration spending has been on a consistent downward trend in recent years, with only a slight bump in 2019. With investment budgets under renewed pressure in 2020, the share of exploration spending in total investment may hit historic lows.
Exploration is being tested by more than a cyclical downturn: many companies and their investors do not attach the same importance to reserve replacement as they have in the past, especially given the relative abundance of onshore unconventional resources (for which there is no formal exploration process as such). As a result, while incentives remain for companies to seek out more advantaged resources and upgrade their portfolios, there is not the same impetus for companies to explore and discover as there once was. This is especially true given that the remaining prospective or underexplored areas in the world are increasingly remote or difficult to access.
Exploration often finds itself in the firing line when companies are looking for ways to cut costs. In our estimate, exploration spend is likely to be down again in 2020, both because of cuts in allocated investments and because of practical difficulties in moving personnel and equipment to the desired areas. Planned exploration wells across Africa and Latin America could be delayed as a result.
That said, 2019 was a moderately successful year for conventional discoveries. The countries that added the most to their conventional resources were Iran, Russia, Guyana, and Trinidad and Tobago, and there were also significant discoveries in China, Malaysia, Indonesia, Norway and South Africa . This made 2019 the most successful year for oil and gas discoveries since 2015. The trend in discoveries is towards natural gas, and 2019 was another significant year with large finds in Russia, Mauritania, Iran and Cyprus.
The record of discoveries thus far in 2020 is some 40% below the same period in 2019, although notable finds have included the Jebel Ali gas discovery in the United Arab Emirates, which opens up the possibility of reducing the country’s reliance on imported gas, and further finds in the Guyana-Suriname basin.
Global conventional resources discoveries and exploration spending as % of total upstream investment.
Refining investments have surged since 2015. Spending on new refinery builds and upgrades amounted to some USD 52 billion in 2019 (USD 75 billion if maintenance spending is included). Several years of heightened investment led to a record amount of new refining capacity (2.2 mb/d) coming online in 2019, including two mega refineries in China integrated with petrochemical operations (400 kb/d Hengli and 400 kb/d Zhejiang phase 1).
Capacity additions of 2.2 mb/d in 2019 were significantly above the annual increase in oil demand of 0.8 mb/d. A further host of new refinery units (around 6 mb/d) is planned for the next five years (IEA, 2020b). Even before the health and economic crisis of 2020, it was clear that these new refinery additions would be likely to outpace the rise in demand.
Recent investment activities have been concentrated in regions with structural advantages, either cheap feedstock (e.g. the Middle East) or growing demand in domestic markets (e.g. developing Asia). The Middle East and developing economies in Asia account for less than 40% of today’s operating refineries, but have recently been attracting considerable investment; the two regions account for two-thirds of all refineries that have come online over the past five years, and over 80% of those currently under construction.
Investments in the Middle East have been driven by the strategic ambition to extract more value from the region’s hydrocarbon resources, with Saudi Arabia, the United Arab Emirates and Iran taking the lead. Kuwait plans to follow suit with the completion of the 615 kb/d Al-Zour refinery, the largest in the region. With these new additions, several countries are emerging as major oil product exporters in addition to their traditional role as major crude oil exporters. Many Middle East NOCs have also set up trading arms to expand their presence in crude and product trading.
In Asia, while the main motivation is to serve growing demand in domestic and adjacent markets, capacity is growing faster than demand in certain countries, notably in China. Product exports from some of these countries have also risen, putting additional pressure on less advantaged refineries in other parts of the world.
For example, some 2 mb/d of refineries in Japan and Europe have shut down their facilities since 2013. Several European plants have been converted to bio‑refineries (e.g. Total’s La Mede, Eni’s Venice and Gela), which also serve EU biofuels policy targets (see below). Brazil’s Petrobras has scrapped the second phase of the Comperj megaproject and has instead kick-started the process of divesting its refineries as part of its portfolio optimisation programme.
The sentiment towards refining investment varies by company type. NOCs in the Middle East and developing Asia have been active in strengthening their presence in the downstream value chain. NOCs own around 30% of the refineries in operation today, but hold a 46% share of those under construction. On the contrary, Majors have been selective in refining investment in recent years. Independent companies have remained an important actor in new refining investment in China, Russia and the United States, but their involvement is shrinking in recent investment decisions. All of these strategic trends are likely to be reinforced as a result of the 2020 crisis.
Since 2014, some USD 120 billion has been invested in building new petrochemical capacity or expanding existing plants. More than 70% of this investment took place in just two countries, China and the United States.
There was a noticeable shift in investment in recent years. Until around 2015, most investments were in a series of coal-to-olefin (CTO) and methanol-to-olefin (MTO) facilities in China. These were accompanied by propane dehydrogenation (PDH) plants to capture market opportunities to supply propylene using low-priced LPG feedstock.
However, MTO investment in China fell back as the rise in imported methanol prices damaged project economics. CTO investment continued, partly helped by lower coal prices, but at a slower pace than before. Instead, the balance of global petrochemical investment shifted towards steam crackers, as investment decisions started to respond to the shale boom in the United States.
The United States has added more than 7 Mt of ethane crackers since 2015 with more capacity set to come online in the next few years. With limited domestic outlets and competitive feedstock costs, the country is building several terminals to export ethylene and is poised to establish a strong foothold in global petrochemical markets (although the plunge in oil prices in 2020 is undermining their cost advantages).
The United States has accounted for around 40% of global steam cracker capacity addition in recent years, but was not the only country to make a move in this direction. A number of new naphtha crackers also came online in China, Korea, Malaysia and the Middle East. Strong demand growth in emerging markets and healthy industry margins partly drove these investments, but robust prospects for demand growth and companies’ strategic intentions to secure a long-term competitive edge also played a major role.
For many oil companies, refiners in particular, expansion into petrochemicals was seen as a strategic hedge against weak demand growth for transport fuels. More than three-quarters of naphtha crackers that came online in 2018 and 2019 were integrated with refineries to some degree, a dramatic jump from around 10% for those that came into operation in the mid-2010s. Most of the planned naphtha cracking capacity addition is also expected to have some degree of integration with refineries.
Feedstock flexibility is another feature of recent investments. After witnessing volatile price movements of different feedstocks, several companies invested in retrofitting their naphtha crackers to be able to process a higher portion of lighter feedstocks (primarily LPG). Additionally, many planned crackers are coming with an enhanced ability to select their optimal feedstock mix depending on market conditions (therefore often being called “mixed feed crackers”).
As in the refining sector, the pace of investment in petrochemical facilities in recent years has moved well ahead of the rate of demand growth. In 2019, for example, the annual increase in global ethylene production capacity was 60% higher than the level of demand growth, which led to a significant drop in ethylene prices across the board. Earnings of many commodity chemical companies fell sharply, by 60‑80%, compared with 2018.
This mismatch extends out into the future and could be exacerbated by the economic slowdown caused by the Covid-19 pandemic. In 2020, some 12 Mt of new ethylene capacity are expected to come online, the largest capacity addition since 2010, if all projects go ahead as scheduled. These additions coincide with a significant deterioration in trade and industrial activity, which may weaken the demand outlook for chemical products. While demand for petrochemicals remains robust in the longer term in the IEA World Energy Outlook, a confluence of weakened economic outlook and overcapacity casts clouds over industry margins and utilisation rates in the coming years.
Petrochemical producers are also facing headwinds from a growing backlash against plastic waste, reflected in pledges by manufacturers of consumer goods to reduce the use of plastics in their products and boost the use of recycled material, and in the increasing number of government policy targets and plans to ban single-use plastics. These commitments are also now extending beyond countries in the Organisation for Economic Co-operation and Development (OECD): China, one of the world’s largest plastic consumers, announced its ambition to phase out single-use plastics across the country. As a first step, single-use plastic bags will be banned in major cities by the end of 2020 and in all cities and towns by 2022.
While these measures are unlikely to make a strong dent in demand in the short term, they encapsulate some longer-term commercial and reputational risks facing chemical companies. And these companies and investors are responding to the widespread social demand for sustainability by exploring new business opportunities in this area. Investments in alternative feedstock and plastic recycling start-ups are still relatively small (less than USD 1 billion in total), but they almost quadrupled between 2017 and 2019.
Biochemicals (including bioplastics) attracted a large portion of the capital, but plastic recycling is also receiving growing attention. The latter includes both mechanical recycling (e.g. robotics to allow more efficient sorting and picking) as well as chemical recycling, where plastic waste is broken down into monomers or feedstock to allow a wider range of waste to be recycled. Several pilot plants are being built to test the technical and commercial viability of chemical recycling processes. Companies’ engagements in these areas are likely to expand as they strive to find a new competitive edge amid growing consumer awareness and tighter regulations on plastic waste.
As noted in the previous section, there was a rebound in the average size of oil and gas projects approved for development in 2019. No sector demonstrated this newfound comfort with large-scale investments better than LNG, which had a record year for new projects.
A drought in new project announcements that started in 2016 was broken in October 2018 by the approval of the LNG Canada project, followed by the smaller Greater Tortue Ahmeyim project that straddles the border between Mauritania and Senegal in West Africa. The momentum continued with a slew of announcements in 2019. Almost 100 bcm/y of new liquefaction capacity was sanctioned over the course of the year, more than the preceding four years combined.
The United States has been the largest presence in the latest investment cycle, and 2019 approvals included Golden Pass LNG (Qatar Petroleum and ExxonMobil), train 6 of Cheniere’s Sabine Pass and the Calcasieu Pass facility (Venture Global LNG).
There were also major announcements from Mozambique, with approval of the Area 1 LNG project (this Anadarko-led project was then acquired by Total), and from Russia as Novatek’s Arctic LNG 2 project got the go-ahead. Nigeria’s long-awaited seventh NLNG train was also approved in late 2019.
Although not yet accompanied by formal investment decisions, the LNG expansion plans of Qatar Petroleum have been a very prominent part of the emerging picture. Since announcing its intention in 2017 to continue development of the huge low-cost North Field, Qatar has steadily upgraded its ambitions to increase the country’s liquefaction capacity. The initial intention was to add three LNG trains (each of around 8 Mtpa of capacity), then a fourth was added to the plans and, in 2019, a fifth and sixth. The target date to complete this expansion is 2027, by which time these six trains would bring Qatar’s total liquefaction capacity to 126 Mtpa (roughly 170 bcm/y), up from 77 Mtpa (105 bcm/y) today.
The wave of interest in LNG reflected the relative abundance of natural gas in the world – especially after the shale revolution – as well as a view among investors that this type of investment is relatively resilient to more ambitious climate scenarios. Majors such as Shell, BP and Total have increased the share of natural gas in their portfolios over the past decade, and have made several large-scale strategic investments across the natural gas supply chain, particularly in LNG. The rise of the “portfolio” marketing model has also marked a change in the way LNG projects are financed, with large, well-capitalised players willing to use their balance sheets instead of relying entirely on long-term contracts with committed buyers to move projects ahead.
This disconnect between LNG investment decisions and firmly committed demand has taken place against an emerging backdrop of oversupply and downward pressure on gas prices. It now coincides with a profound shock to gas consumption resulting from the global health and economic crisis in 2020.
The record year for new LNG project approvals in 2019 took place at a time when prices were falling in all major gas-consuming regions. By the first quarter of 2020, spot prices for LNG cargoes had fallen into the range of USD 2/MBtu-USD 4/MBtu, enough to cover operating costs in most cases but well below the levels required for projects to return their invested capital.
This was a consequence of subdued demand at a time when significant amounts of new supply, including both LNG and pipeline capacity, were coming online. Among the pipeline projects, the largest was the new 38 bcm/y “Power of Siberia” connection between Russia and China that was launched in December 2019.
Some LNG suppliers were immediately been exposed to both volume and price risk because of the crisis. Others have had a measure of protection because volumes were specified in long-term sales agreements, with prices often linked in part or in full to oil. However, the collapse in the oil price in 2020 means that the latter protection is set to disappear over the typical six- to nine-month period in which movements in oil prices filter through into natural gas contract prices. The precise implications will vary from company to company. But oil at USD 25/bbl would leave more international gas suppliers struggling to cover their operating costs.
This disparity between short-term market conditions and the readiness to sanction new LNG projects can be explained by a number of factors:
- A widely shared anticipation of longer-term demand growth for LNG and an awareness that, in part because of the dearth of new project approvals in 2016‑18, there was a potential shortfall in supply emerging in the mid-2020s that could be plugged by projects taking FID in 2019.
- A larger share of new projects were sanctioned through equity lifting, where project partners receive a share of LNG volumes proportionate to their equity stake and take on their own marketing and selling responsibilities. This contrasts with traditional project finance structures, which require buyers agreeing to purchase a minimum quantity of LNG under long-term delivery commitments.
- Strategic considerations for some of the world’s major resource-holders. In the case of Qatar, a drive to ensure the country’s pre‑eminence in the LNG market, based on some of the lowest-cost gas in the world. For Russia, a desire to increase the range of export destinations and balance reliance on pipeline exports. In other cases, a strategic calculation – perhaps reinforced by the possibility of intensified action on climate change – that the risks of going ahead early were less than the risks of delay.
However, the opportunities for the next wave of planned LNG projects are now much less clear; near-term oversupply and price uncertainty have reduced readiness among buyers to conclude long-term deals, and the economic challenges resulting from low prices have severely constrained capital budgets among developers, leading to deferrals and project reviews. FIDs have been postponed by US and Canadian independents (Tellurian’s Driftwood and Pacific Oil and Gas’ Woodfibre) as well as oil majors (ExxonMobil’s Rovuma project in Mozambique), while Shell backed out of the Lake Charles LNG project in the United States).
Global biofuels investment – including liquid biofuels, biogas and biomethane – has fallen to under 1% of the total investment in fuel supply. Since the late 2000s, when biofuels enjoyed much more widespread policy support and rapid market expansion, the amount invested in new production facilities has dropped substantially. While investment in biogas has been relatively stable, spending on new production facilities for liquid biofuels fell sharply over this period.
In 2019, investments in liquid biofuels production capacity declined again by around 30%, largely due to developments in China, where investment in ethanol production facilities halved compared with the previous year. China has suspended the extension of its 10% ethanol blending mandate nationwide to reduce competition for corn production and assure food security. As 10% blending is still extending to some new provinces, investment in China could rebound somewhat in 2020, supported by new plants that are already under construction.
Policy-driven investment in ethanol production facilities continued in the United States and Brazil. The Renewable Fuel Standard (RFS2) is the key federal policy mechanism supporting US biofuel consumption. In Brazil growth is driven by the new Renovabio scheme. However, shut-ins of biofuel production capacity in the United States and Brazil in 2020, due to plummeting gasoline demand, are likely to dampen near-term appetite for new investments.
Continued investment in biodiesel facilities in 2019 was driven almost entirely by hydrotreated vegetable oil (HVO) plants in Europe and the United States. Policy support for HVO is coming from Europe’s updated Renewable Energy Directive for 2021‑30 and in the United States from the RFS2 and California’s Low Carbon Fuel Standard.
One reason for slower momentum behind liquid biofuels in the US market is the “blend wall” effect, which refers to structural challenges relating to vehicle suitability and fuel distribution infrastructure for ethanol blends higher than 10%. A regulatory reform permitting year-round sales of a 15% ethanol blend (E15), introduced in 2019, could increase ethanol penetration in the United States. However, only around 1% of service stations offer E15 nationally, and expanding supplies to the approximately 20 states where the blend is not currently available will take time.
Instead, future developments are likely to be led by Asia, where several economies have announced ambitious blending targets, for example, India with a 20% share of ethanol in gasoline (E20) by 2030 and Indonesia with a 30% share of biodiesel in diesel (B30) in 2020. The investment required to meet these targets is a key reason for higher projected spending in the IEA STEPS.
Investment in biogas and biomethane has averaged around USD 5 billion per year over the last decade, which is less than what the natural gas industry typically spends every week. The development of biogas has been uneven across the world, as it depends not only on the availability of feedstocks but also on policies that encourage its production and use. China, Europe and the United States account for almost 90% of global production of low-carbon gases.
To meet sustainability goals, biofuels investment would need to increase by more than six times over the next decade, reinforcing the importance of policy support to scale up sustainable biofuel deployment, especially during a period of low oil prices.
Investment in coal supply was around USD 90 billion in 2019, a 15% increase on 2018. Even with this rise, this is only around 5% of total investment in the energy sector, despite coal supplying more than a quarter of the world’s global primary energy. The overall figure includes investment in mining and related infrastructure to bring coal to market, but excludes spending on coal-fired power plants.
China was by far the largest driver of growth in global coal investment in 2019, with some contribution also from Australia and others. This reflects the increasing concentration of global coal demand in Asia, contrasting sharply with the dramatic reductions seen in some other parts of the world. As recently as 2000, Europe and North America accounted for one-third of global production; now that share has collapsed to less than 15%.
Understanding China is the key to understanding coal markets. China represents more than half of global coal demand and almost half of global production, and remains the largest importer in the world. China also accounts for more than two-thirds of global spending on coal supply and for the bulk of global annual changes.
The landscape for investment in coal supply in China has been reshaped by the reforms of 2016‑17 that aimed to address a large overhang of capacity, which had in turn been created by an earlier investment boom in the early 2010s. These reforms resulted in the closure of many smaller, less productive mines, often ones with poor safety records, leaving the sector more efficient, more profitable and safer.
The restructuring coincided with a stabilisation in Chinese coal demand trends after three years of decline from 2014‑16, due to strong electricity consumption and renewed support for infrastructure development. As a result, investments in coal supply have picked up again, with the capital not just going to existing mines or those that are under development, but also to new projects.
After a two-year halt, the National Energy Administration and the National Development and Reform Commission1 restarted the process of approval for new mines, accounting for 28 Mtpa of additional capacity in 2017, 68 Mtpa in 2018 and 201 Mtpa in 2019. This is not yet at the scale of the previous spike in coal supply investment, which at its height in 2012 meant that China was investing 50% more than would have been needed to meet demand: the Chinese authorities are very wary of creating a new overhang in capacity, although that risk has clearly increased due to the effects of the Covid-19 pandemic.
Unlike in the previous boom, new investments in coal supply are no longer banking on an increase in Chinese consumption. But they are predicated on a stable outlook for Chinese coal use, i.e. without any sudden intensification of China’s energy diversification or emissions policies, or lasting effects of the current slowdown.
The growth in coal supply investment in 2019 can appear counter‑intuitive from an energy market perspective – not least because global coal-fired power generation saw its largest-ever drop in the course of the year and came under renewed pressure in 2020. This trend is even more counter‑intuitive when viewed against the backdrop of energy transitions and uncertainties over the future of coal demand, a groundswell of public opposition to coal projects, and an increasing number of governments, international financial institutions, investors, insurance companies and other stakeholders limiting or curtailing their involvement in the coal business.
The IEA World Energy Outlook 2019 looked in detail at the impact of financing restrictions on coal supply projects. These are becoming more widespread and in many countries the process of gaining approval and finance for new coal supply investments is getting harder and longer. In particular, projects that cannot be financed from the balance sheets of larger companies can struggle. More restricted access to capital is one reason some larger supply projects (e.g. Carmichael in Australia, the Boikarabelo mine in South Africa) have been downsized. These trends are also apparent for new coal power projects, as described in the Energy Financing and Funding section of this year’s WEI.
At the same time, some new projects continue to move ahead – notably in China and India, which are the main countries investing in coal supply. Coal still represents more than one-third of global electricity generation and remains the second-largest fuel in the global energy mix after oil and the second-largest traded bulk commodity after iron ore. Investments are being proposed on that basis, in response to economic signals coming from the coal market.
Climate-related pressures are visibly affecting some projects and shaping the demand outlook for coal in many countries, creating significant risks to coal investment, especially for thermal coal and lignite (coking coal is less affected, given the more difficult substitution of coal in steel making). However, the overall pattern is that coal supply investment still follows typical commodity (boom and bust) cycles, in which high prices tend to lead to overinvestment, which creates oversupply and hence low prices, which in turn discourages investment until shortages push up prices again.
This dynamic comes through clearly when viewing recent changes in coal supply investment in Australia against prices in the preceding year.2 We select Australia because it is the largest exporter by economic value and has very accessible and transparent data for both prices and investments. Data for 2011‑19 show that changes in spending are well aligned with the price signals from the preceding period. This suggests that the decline in investment in the 2013‑16 period was price-driven rather than policy-driven, and that economic factors remain a key explanatory variable for investment in coal supply. On this basis, downward pressure on the coal price in 2020 is likely to be a primary factor affecting investment decisions in 2021.
Mines below 1.2 Mtpa of capacity are approved by the local authorities.
Price is for thermal price (Newcastle free-on-board 6 000 kcal/kg) and investments also include coking coal. Prices for the preceding year are used to reflect a typical decision-making cycle: companies usually decide the investment one year before the spending occurs.
Mines below 1.2 Mtpa of capacity are approved by the local authorities.
Price is for thermal price (Newcastle free-on-board 6 000 kcal/kg) and investments also include coking coal. Prices for the preceding year are used to reflect a typical decision-making cycle: companies usually decide the investment one year before the spending occurs.