It seems one cannot go a day without seeing a headline about the low price of oil and the potential impacts to the US and global economy and the oil and gas industry. In order to help make sense of the myriad of information available, we have broken down the issue into the following fundamental questions.
Why did oil prices correct so suddenly? Is the current low price environment due to lower demand or increased supply or a combination of both?
The answer is a combination of both. The correction is a net result of lower-than-projected demand growth and a remarkable increase in supply. On the demand side, in July 2014 the Energy Information Administration (EIA), International Energy Agency (IEA), and OPEC forecast 2015 global liquids growth to be 1.7 percent on average. However, these expectations declined to just 1.1 percent by December 2014, despite a low price environment that typically would have been conducive to boosting demand.i One reason for the muted demand response to the low price signal has been the increasing strength of the US dollar relative to other major world currencies. Notably, the US Dollar Index has risen nearly 15 percent to 97.4 since July 2014. A stronger dollar makes dollar-denominated crude more expensive for buyers using foreign currency. Consequently, while the United States is enjoying the full benefit of low prices, many other countries are only experiencing a portion of the price decline, giving them less reason to consume more petroleum products.
On the supply side, several years of $100/bbl oil drove tremendous production growth in many countries. US crude output, including lease condensate production, increased by over 2 MMbbl/d from 2012 to 2014. This domestic supply surge greatly offset US net crude oil imports, shrinking them from 8.5 MMbbl/d in 2012 to less than 7 MMbbl/d in 2014. Meanwhile, Brazil, Iraq, and Canada collectively added nearly 1 MMbbl/d over the same two-year period.
All told in 2014, production growth of 1.9 percent exceeded demand growth of 1 percent, leading to an inventory build-up of 500 thousand bbl/d with another 400 thousand bbl/d projected for 2015.
Is OPEC content to wait it out until high-cost producers fall by the wayside? Or, will OPEC cut production?
When oil prices first started to fall, many thought OPEC members might agree to cut production to support prices. However, members rejected that idea during their regularly scheduled meeting in November 2014, leaving OPEC’s official crude production target unchanged at 30 MMbbl/d. In light of the news, the market responded with an immediate 10 percent decline in the price of WTI crude.
Why couldn’t OPEC members agree on a strategic response despite the urgency of the situation? The opposing concerns of two different factions split the camp.
The fiscal breakeven cost is the price that OPEC producers need to receive for their oil in order to balance their government budgets, which are heavily reliant on oil revenue. When prices fall below the fiscal breakeven cost, oil-exporting economies must make up for the shortfall by drawing on cash reserves or reducing expenditures. Countries such as Iran, Venezuela, and Nigeria have high social costs and low cash reserves. The collapse in oil prices not only puts them under financial pressure but also potentially threatens the stability of their governments if transfer payments cannot be made. These fears make them more amenable to crying “uncle” and cutting production to boost prices.
Meanwhile, other OPEC members, such as Saudi Arabia, Kuwait, and the U.A.E., have cash reserves to finance the shortfall for many months. Their biggest fear is not near-term financial collapse, but instead long-term loss of market share. Here, the strong oil prices over the last few years have worked against them in some ways. Prices in the neighborhood of $100/bbl have facilitated significant growth in global crude production, particularly in North America. Today, the increasing volume of unconventional production in the US and Canada is changing import/export dynamics and decreasing western reliance on OPEC producers.
Rather than acting to defend prices, the Gulf producers within the organization, led by Saudi Arabia, are working to defend their global market share. In doing so, they are gambling that as the lower cost producers, OPEC members will ultimately prevail over more costly unconventional operators. Indeed, Saudi Arabia’s oil minister Ali al-Naimi has stated directly that the kingdom will not intervene to support prices. “Whether it goes down to $20, $40, $50, $60, it is irrelevant … it is not in the interest of OPEC producers to cut their production, whatever the price is”.
However, conventional oil field development generally requires years of planning and construction before the first barrels of oil are produced. Today’s low prices may not be enough to curtail the numerous development projects already underway.
What is happening in China, the leading contributor to global growth? Is it rebalancing its economy or has it started a painful correction?
In 2014, the Chinese economy officially grew at a rate of 7.4 percent, down from 7.7 percent, which represented the slowest rate of growth in 24 years.ix In the fourth quarter of 2014, the economy was up 7.3 percent from a year earlier, a figure that was a bit better than what investors had expected, but still indicative of a continuing slowdown.x Moreover, the IMF now predicts that GDP growth will fall below the psychologically important 7.0 percent level in 2015.
This raises questions about China’s future oil demand. In the past, China’s focus on infrastructure and capital projects made it the second largest consumer of crude oil in the world, and it imported large volumes of it at market prices—however high. But its transition to a more consumer-oriented economy might make it more price-sensitive in the future. Regardless, industry stakeholders should stay abreast of economic developments in China, since the nation has been responsible for 55 percent of total growth in oil consumption worldwide between 2005 and 2013.
How much new supply is poised to come online in 2015 and 2016?
In 2014, new non-OPEC large-field projects (i.e., those producing over 25 thousand bbl/d each) collectively brought on 2.3 MMbbl/d in new supply. These efforts spanned diverse geographies and production methods, ranging from Brazil’s offshore projects in the Roncador, Parque, Iracema, and Sapinhoa fields to Mars B in the Gulf of Mexico, and to Russian and Canadian oil sands projects. Notably, these supply additions excluded the numerous shale oil fields being developed in the US. OPEC also contributed to the expanding large-field supply picture, adding another 1.4 MM bbl/d of new oil production capacity in 2014.
For 2015, a Deloitte MarketPoint analysis suggests large-field projects could bring on 1.835 MMbbl/d in new supply (i.e., 1.2 MMbbl/d from non-OPEC producers and 0.635 MMbbl/d from OPEC members). These projects are well underway and are unlikely to be halted, even in the current low-price environment. Taking this momentum into account, the analysis further forecasts large-field production additions of 2.676 – 3.434 MMbbl/d from non-OPEC producers and 0.759 MMbbl/d from OPEC members in 2016.
For the past two years, US tight oil production has grown at an annual rate of approximately 1 MMbbl/d. This growth is expected to continue in 2015, but at a slower rate.xvii While the recent drop in crude prices has squeezed the capex budgets of shale producers, some reportedly have been able to lower their operating costs to below $40/bbl through efficiency gains and better economics in the “sweet spots” of the shale plays. As a result, production growth is expected to continue in the short term despite low prices, albeit more slowly than in prior years. While there is no consensus on the extent to which growth will slow, many analysts expect declines of 300-500 thousand bbl/d off the 2014 pace.
It is important to note that the world experiences a four to five percent production loss per year just from normal depletion. So the added production has to equal this amount if we are to stay even with no additional growth.
Will the industry stabilize and balance after 2016?
Based on current data, demand should grow faster than supplies starting in 2016. Low prices over the next few years will likely inhibit investment in new projects—especially those in the early stages of discussion or in the engineering and design phases. It should also bolster demand, due to price elasticity,much faster than otherwise would be the case.
What does the future look like in 2020?
By simulating how the aforementioned variables could affect market conditions, the Deloitte MarketPoint World Oil Model (the Model) provides some insight into where prices might be headed. The findings from the Model’s output include the following:
• Based on the EIA’s estimates, production is expected to continue to outpace demand in 2015 by approximately 400 thousand/bbd. This assumption is driven largely by continued production growth through the first half of 2015 as many producers strive to complete projects falling into the “too late to turn back” category and as yet-to-expire hedging contracts allow them to continue producing despite uneconomic market conditions.
• On a half-cycle basis, oil prices could fall below $40 bbl. There have been several periods in the last 25 years where prices have dipped well below this level. However, in the current market environment, some of the very low prices witnessed in the past are unlikely to reappear, at least on a sustained basis. Since oil markets are self-correcting, market forces should trigger an adjustment, mainly through low prices that engender more demand, decrease marginal, high-cost supply, and encourage supply depletion. This suggests that historically low prices could not be sustained for more than 3 to 12 months, absent other drivers affecting demand.
• If the low-price environment continues as expected through the first half of 2015, it should trigger a demand response that will likely be felt in the second half of the year. This is the same time period when cut-backs on the number of shale drilling rigs in operation, expiring hedging contracts, and other production-related belt-tightening should start to have a more prominent effect on production growth and market perception.
• As a result, Deloitte MarketPoint forecasts crude prices to rise in the second half of 2015, elevating the average annual price above present levels. Additionally, the forecast expects the average 2015 WTI price to reach $62/bbl and then to rise gradually over the next few years until it reaches a new steady range of $75-$80/bbl (i.e., combined WTI and Brent world crude price) as early as 2018. This new equilibrium price is approximately $20/bbl lower than the steady state achieved in previous years, because it reflects two new circumstances in the marketplace:
Prior to the “shale revolution,” there was a scarcity premium of $10-$20/bbl in place. With the newfound abundance of tight oil in the US and potentially in other areas around the globe, that scarcity premium has been reduced.
Producers in high-cost regions, such as the Canadian oil sands and certain tight oil plays in the US, have continued to improve their margins through technological innovation. While their margins will be lower in the new equilibrium-price environment, they should still be able to operate profitably.
The Deloitte MarketPoint price forecast is only one possibility among a multitude of potential outcomes. Changes in key assumptions, such as the magnitude of the demand response as well as the trajectory of tight oil production growth, would greatly change this picture. With only negligible shifts in demand or production in the next 12 to 18 months, the average price could likely be lower, and the recovery would likely be “U” shaped, reinforcing the price signal to shale producers to decrease production.
Forces that could potentially make upside price scenarios more likely include any number of black swan events affecting supply or the perception of supply scarcity. However, since oil markets are highly cyclical, they tend to overshoot or undershoot most long-term outlooks. The current price environment has, or soon will, curb many development plans. These can be restarted in the future once the pricing environment becomes more favorable, but the lag could just be the catalyst for pushing the market back into a scarcity mindset sooner than expected.
History has demonstrated that the oil and gas industry is resilient. Oil prices are rarely stable for extended periods of time, and the industry has shown a remarkable ability to adapt and thrive as cycles change. Even after analyzing market fundamentals and other variables, the questions keep coming: Will demand continue to moderate or grow in the face of lower gasoline prices? Will companies become more efficient, leading to lower breakeven prices for US shale plays? How will global/political circumstances change?
While forecasts can be helpful for thinking about possibilities, the future is never entirely visible. However, one thing is clear: Many oil and gas companies will need to retrench and determine how they can best adapt and manage change in this challenging environment. Enlightened companies will use this time as an opportunity to improve their organizations by continuing to focus on:
• Enhanced efficiency and performance through business process and/or supply chain optimization
• Strategic and operational improvements
• Reduced and/or refocused capital expenditures
• Portfolio upgrades through acquisitions and/or divestitures
• Talent acquisitions
Is OPEC stuck in a cycle of endless cuts?
In its latest annual World Oil Outlook (WOO) report, published last week, the Organization of the Petroleum Exporting Countries (OPEC) predicted its oil production and market share to fall in the years to come.
This view of the future says a lot about the cartel’s policies in facing the ever-growing U.S. shale which is casting a dismal shadow over the future role which OPEC members are going to be playing in the global oil market.
According to the latest WOO report, OPEC expects its production of crude oil and other liquids to decline to 32.8 million barrels per day (bpd) by 2024 from its current 35 million bpd. This means that the cartel plans to go further with its plans for cutting production even after the current pact is over in 2020.
Considering the significant growth in U.S. shale production over the past few years, and to be exact, since the OPEC decided to cut production in order to relieve the negative impact of U.S. shale’s flow on oil prices, it seems that although OPEC efforts have paid off partially but they have also supported the further expansion of shale production by giving them more market share.
How OPEC sees the future of oil market and its own condition in the future, raises the question that for how long is the group going to continue these “cuts”? And is it going to be enough to maintain the significant role which the cartel has had as an influential body in the global oil market?
Before we go through the above-mentioned questions and discuss some possible answers, let’s take a look at some of the important information presented in recent WOO.
Two major aspects of the market are import to take into consideration here, first of which is production, and the second is consumption.
In the production part, as we mentioned earlier the organization sees its own production falling about seven percent in the mid-term. While according to the data provided, the cartel expects U.S. shale output to reach 16.9 million bpd in 2024 from the current 12.0 million bpd.
This prediction means that the Middle East-dominated group has accepted defeat against U.S. shale producers and sees no way forward except further contracting to prevent the prices from falling.
In the consumption part on the other hand, once again, OPEC sees demand for its oil diminishing in the mid-term and cites rising climate activism and growing use of alternative fuels as some of the reasons for the reduction in mid-term oil demand. The true reason, however, lies somewhere else.
The producer of one-third of the total global oil expects oil consumption to reach 103.9 million bpd in 2023, down from 104.5 million bpd in last year’s report. Longer-term, oil demand, however, is expected to rise to 110.6 million bpd by 2040, although still lower than last year’s forecast.
In the past few years, OPEC has been reducing its oil output under a pact with the support of Russia and some other non-OPEC nations to rebalance the oversupplied market.
Many oil experts and analysts have been recently arguing for an extension in the cuts deal, considering the emerging signs of a slowdown in global economic growth under the shadow of the U.S.-China trade war and a subsequent slowdown in oil demand.
Back in October, OPEC Secretary-General Mohammad Barkindo had announced that deeper cuts in the organization’s oil supplies were one of the options for OPEC and its allies to consider in their upcoming gathering in December.
It should be noted that Russia and Saudi Arabia as two main poles of the OPEC and non-OPEC alliance (known as OPEC+) have slightly different views about the need for further extension of the pact. Russia sees the current range of prices at about $60 good enough while the kingdom requires higher prices to go through with its ambitious Aramco IPO.
The broken cycle
What OPEC has presented in its latest report suggests that the cartel’s policy of controlling production is having an opposite impact. The skyrocketing U.S. shale production levels indicate that OPEC cuts are positively encouraging shale producers to increase their output more and more, and that will not only halt prices from rising but will also reduce OPEC’s share of the global market day by day.
In this regard, many analysts believe that OPEC should once again take into account the warnings of the former Saudi Oil Minister Ali al-Naimi, who had previously predicted that “OPEC’s production cuts only creates more production opportunity for U.S. shale oil and consequently the organization would be caught up in an endless maze of production cuts.
With OPEC’s report pointing to several production challenges from its competitors, the cartel doesn’t seem to be much concerned about the demand side.
According to the report, world crude oil consumption will continue to grow up to 2040, so that by 2024 the demand for crude oil will increase one million barrels a day to reach 104.8 million bpd. The demand growth will then continue at a slower pace, reaching 110.6 million bpd by 2040.
OPEC’s share of the mentioned 110.6 million bpd will be 44.1 million bpd, the report says.
So, it seems that OPEC believes it should continue holding its pact with the non-OPEC allies for a few more years when the growth in global oil demand would offset the increase in U.S. shale production and once again rebalance the market.
From our partner Tehran Times
Energy investment in emerging economies: Transforming Southeast Asia’s power sector
Authors: Michael Waldron and Lucila Arboleya*
The new IEA Southeast Asia Energy Outlook 2019 (SEAO) provides a comprehensive overview of energy prospects in an increasingly influential region for global energy trends. Alongside the scenario projections and analysis, the report contains three “deep dives” – on the future of cooling, on regional electricity trade and renewables integration, and on investment – that reflect priorities for cooperation agreed between Southeast Asia energy ministers and the IEA.
Bolstering investment in more efficient and cleaner energy technologies in Southeast Asia’s power sector is a particularly urgent challenge. Policy makers in many countries of the region are stepping up their efforts to support deployment of renewables across the region, but investment has lagged well behind the levels reached in China and India. Electricity demand in Southeast Asia is rising rapidly, and many parts of the power sector are showing signs of financial strain.
Whichever pathway the region follows, it will need a sizeable increase in investment flows and a reallocation of capital, particularly under a sustainable pathway (in the Sustainable Development Scenario) where renewables spending more than quadruples.
What can be done to put the region on a more sustainable pathway, from both a financial and environmental perspective? This was the question that we addressed in the new IEA report and also at a major IEA Roundtable featuring the insights of financial, legal, industry and policy experts from across Asia, which was held in Singapore on 1 November as part of the Singapore International Energy Week.
Bridging investment gaps with more private finance
To date, public actors – including state-owned enterprises and public financial institutions – have provided the bulk of funding for the power sector, particularly in thermal generation. By contrast, wind and solar PV projects have relied much more on private finance, spurred by specific policy incentives.
In addition, funding for over three-quarters of generation investment has come from within the region. This landscape reflects prevailing decision-making frameworks, which have largely revolved around state-owned utilities and the distortionary impact of energy subsidies, but also the ability and willingness of private players to navigate perceived country, regulatory and market risks that have inhibited much higher levels of investment in the power sector across Southeast Asia.
However, public sources alone cannot cover the sizeable investment needs ahead. Sustained and balanced access to international and regional sources of private finance, complemented by public sources, would better help Southeast Asia fund its energy goals. More robust private financing conditions would help governments to use public capital more effectively, especially in countries with limited fiscal capacity.
Realising this requires reforms and greater policy focus on tackling the risks facing investments, especially in renewables, flexibility assets and efficiency. With the dramatically improved economics of renewables in many parts of the world, the region now has a compelling opportunity to transform its power sector.
While recognizing that market conditions and underlying risks differ starkly by country, the SEAO points to efforts needed across four priority areas:
- enhancing the financial sustainability of the region’s utilities;
- improving procurement frameworks and contracting mechanisms, especially for renewables;
- creating a supportive financial system that brings in a range of financing sources and
- promoting integrated approaches that take the demand-side into account.
Priority 1: Enhancing the financial sustainability of the region’s utilities
The region’s utilities, mostly state-owned, function as the primary counterparty to private generators and are the main investors in electricity networks (which as highlighted in the SEAO, are also crucial for supporting regional trade and integration). Their financial sustainability depends on their ability to recover costs, which is influenced by customer connections, operational performance and regulatory frameworks. Cost-recovery varies across Southeast Asian markets, with particular challenges related to setting retail tariffs in a way that balances system needs and affordability for consumers.
For example, despite improved borrowing conditions for Vietnam Electricity (EVN), financial performance is tenuous and tied to government decisions on electricity prices, which remain low by international standards. By contrast, in Malaysia, a combination of improved operations, better financing and regulations for cost-pass-through supports a relatively high level of per capita investment for grids.
Underperformance can put pressure on government budgets, as in the case of Indonesia. Following several years of improvement, increased financial pressure on PLN, due to rising power purchase and fuel costs in the face of frozen retail tariffs, prompted a year-on-year boost in government subsidies in 2018 (equivalent to over 3% of total state spending). Looking ahead, PLN’s subsidy burden could be sizeably reduced through more cost reflective electricity tariffs. Moreover, changes to retail prices could be tempered through better utilisation of existing generation, more focus on efficiency measures to help slow Indonesia’s demand growth and less dramatic expansion of capacity with contractually onerous terms.
Priority 2: Improving procurement frameworks and contracting mechanisms, especially for renewables
Investment frameworks for power generation have evolved considerably, but further reform could help improve private financing prospects. While independent power producer (IPP) investments are playing an increased role, these have come mostly through administrative mechanisms, such as direct negotiation with utilities, which are often not transparent in terms of price formulation. Price incentives (e.g. feed-in tariffs) under licensing schemes have driven most investment in renewables, but their design is not always effective; in some cases (e.g. Indonesia) tariffs have been set too low to attract investment at current project costs.
Competitive auctions, which can provide price discovery and clear risk allocation through contracts, have helped drive down renewable purchase prices around the world. Most Southeast Asian countries have been slow to adopt them, but implementing such transparent mechanisms for orderly market entry, with a commitment to sustain their use over time, would go a long way to reassure investors.
The case of Viet Nam illustrates challenges and opportunities in terms of policy design and bankability. Attractive feed-in tariffs spurred a boom in solar PV deployment in the first half of 2019, financed mostly by regional players. Yet, perceived risks and financing costs are relatively high and international banks remain reluctant to lend to renewables projects. This stems from risks associated with the standard power purchase agreement offered to IPPs, including areas related to dispatch and payments, as well as concerns over the adequacy of local grids to accommodate a rapid increase in variable generation. Clearer regulations, better policy design, and measures to address system integration and contractual concerns could help to improve the affordability of investments. With financing terms equivalent to those found in more mature markets, generation costs for solar PV and onshore wind could be around one-third lower.
Priority 3: Creating a supportive financial system that brings in a range of financing sources
As changing financing conditions make investing in some legacy parts of the power system more difficult, more effort is needed to cultivate a supportive financing environment for newer technologies while ensuring security of supply. To illustrate, final investment decisions for coal power in the region have fallen to their lowest level in over a decade in 2019 (reflecting a mixture of increased financial scrutiny by banks and overcapacity concerns). There has been a reduction in the number of financiers involved in transactions in the past three years, while IPP projects that have gone ahead continue to rely on a high share of international public finance.
At the same time, mobilising capital in newer areas requires improving the cost and availability of finance. The average loan duration in Southeast Asia is just over six years, far less than the lifetimes of energy and infrastructure assets. The cost of capital for an indicative IPP varies widely – with estimates in Singapore, Thailand and Malaysia at 3-5% (nominal, after-tax), while those for Philippines, Viet Nam and Indonesia are much higher (7-10%). Investors cite limited availability of early stage project development equity and long-term construction debt for renewables and storage, though some dedicated funds, such as the Southeast Asia Clean Energy Facility, are emerging to fill the gap.
Priority 4: Promoting integrated approaches to investment that address the demand side
Integrated approaches to investment, which take into account the demand side, could help to address rising consumption needs more cost-effectively. This is particularly true in fast-growing areas, such as demand for cooling, which is a major driver of supply requirements during peak hours but where more efficient air conditioner units, including those manufactured locally, are available at affordable prices. Efficiency investments can face barriers due to the small transaction sizes (from the perspective of banks), high upfront capital requirements (from the perspective of consumers), challenges in evaluating creditworthiness, and lack of clear labelling to support purchase choices. Low and subsidised retail power tariffs can also distort the investment case.
Addressing information barriers, enhancing financing models and reducing subsidies would better support investment. Energy service companies are addressing the scale and upfront financing challenge of investment. They are well established in markets with long-term energy savings targets and supporting regulations, such as in Malaysia, Thailand and Singapore. Targeted use of public funds, insurance and capacity building can help reduce performance-related risks, as in Indonesia’s Energy Efficiency Project Finance Program. Progress in aggregating and securitising projects, through green bonds for example, could also help attract lower cost finance from a bigger pool of investors. Despite picking up in 2018, with over 40% targeting low-carbon buildings, Southeast Asia accounts for only 1% of global green bonds issuance to date.
Higher investments would yield multiple benefits
Overall, achieving Southeast Asia’s energy goals will call upon stronger policy ambitions across a range of energy sources and significant new capital commitments in the years ahead. As international experiences have demonstrated, where governments provide frameworks that allow for the efficient allocation and management of investment risks, the private sector responds and the cost of capital is reduced.
These efforts would also yield multiple benefits – in the Sustainable Development Scenario, average annual capital spending across the entire energy sector of more than $140 billion over 2019-40 (higher than the $110 billion under the State Policies Scenario), is offset by the nearly $200 billion that Southeast Asian economies would save annually on fossil fuel imports by 2040. Such financial savings would come in addition to improved local air quality and universal energy access, as well as a reduced contribution to global climate change.
There is now an opportunity for investors and companies in Southeast Asian countries to engage with governments in order to encourage financial decisions and policy making that are better aligned with sustainability goals. This includes not just traditional utilities, developers and banks, but also the crucial perspectives of development finance institutions and the institutional investors, whose participation will be critical to funding the region’s energy goals.
As the world’s “All-fuels and All-technologies” energy authority, the IEA will continue to assist ASEAN Member States to tackle their energy policy challenges, including through good data and analysis, training and capacity building and enhanced engagement.
*Lucila Arboleya, Energy Economics and Financial Analyst.
Understanding the World Energy Outlook scenarios
Authors: Laura Cozzi and Tim Gould
Today’s energy choices and their consequences
Today’s energy choices will shape the future of energy, but how should we assess their impact and adequacy? This is the task the World Energy Outlook takes on. It aims to inform the thinking of decision makers as they design new policies or consider new investments. It does so by exploring possible futures, the ways they come about and some of the main uncertainties – and it lays out the consequences of different choices for our energy use, energy security and environment.
One key element of this is to assess where the global energy system is heading, based on the policy plans and investment choices we see today. A second is to assess what would need to be done differently in order to reach the climate, energy access, pollution and other goals that policy makers have set themselves.
As ever, this year’s World Energy Outlook, to be released on 13 November, brings many changes from the 2018 edition. In this commentary, we wanted to highlight two in particular.
Introducing the Stated Policies Scenario
In this year’s Outlook, the New Policies Scenario is renamed as the Stated Policies Scenario (the acronym is STEPS – STated Energy Policies Scenario). As with its predecessor, this scenario is designed to reflect the impact not just of existing policy frameworks, but also of today’s stated policy plans. The name change underlines that this scenario considers only those policy initiatives that have already been announced. The aim is to hold up a mirror to the plans of today’s policy makers and illustrate their consequences, not to guess how these policy preferences may change in the future.
The planned policies analysed in this scenario cover a wide spectrum. For example, a country might state that it intends to remove fossil-fuel consumption subsidies or, alternatively, that it will walk back a previous reform. Another might say that it will tighten future fuel efficiency standards or step up support for electric vehicles. One might open up new resource developments in oil and gas while another might limit them.
Many countries today are raising their ambitions for clean energy deployment, as reflected by the rising interest in offshore wind that we explored in depth in a special focus from this year’s World Energy Outlook that was released separately in Copenhagen last week. Countries may also announce new rural electrification targets or ambitions to bring clean fuels to parts of their population that rely on firewood or other solid biomass for cooking.
All of these stated policies are assessed individually and their impacts are modelled. In our updated and expanded online explainer on the World Energy Model, the large-scale simulation model that is used to generate all our projections, we have made all the key policy assumptions available for all scenarios, along with all the underlying assumptions on population, economic growth and energy resources (which are held constant across the scenarios) and information on prices and technology costs (which vary by scenario depending on the market and policy context).
There is one type of policy announcement that deserves special attention: the growing number of long-term decarbonisation targets, including “net zero” commitments. After the UN Climate Summit in September, there were at least 65 jurisdictions, including the European Union, that had set or were actively considering long-term net-zero carbon targets. These economies together accounted for 21% of global gross domestic product and nearly 13% of energy-related CO2 emissions in 2018.
Are these “net zero” targets all incorporated into the Stated Policies Scenario? It depends. The target has to be announced or adopted officially, but the crucial variable is how visible the pathway is to reach it. As always with the World Energy Outlook, the details matter. Is there a strategy to decarbonise heat? What about heavy industry? What about trucks or aviation? To the extent that these pathways are laid out, then the overall ambition is also reflected in this scenario.
And it’s not only about national governments: other commitments are becoming increasingly important, whether from sub-national authorities, cities, companies or investors. We also keep a close eye on changing public attitudes and preferences, as these can be very significant in shaping energy use (as, for example, with the rising popularity of SUVs).
In aggregate, these commitments are enough to make a significant difference. The comparison with the Current Policies Scenario, which only looks only at policies in place but from which the effects of announced policies are excluded, makes this clear. However, there is still a large gap between the projections in the Stated Policies Scenario and an energy system that meets global sustainable energy goals.
Extending the Sustainable Development Scenario to 2050
What should policy makers do? What pathways might help meet these targets? What technologies need a boost? Where should innovation, research and investment be directed? How can we balance growing energy demand with the need to reduce air pollution and carbon emissions? How can millions of people gain access to critical energy services while also meeting climate goals?
The IEA seeks to help policy makers in government and industry shape a more secure and sustainable energy future. This is why the World Energy Outlook has been providing detailed climate mitigation scenarios for more than a decade. Two years ago, we introduced a new scenario, the Sustainable Development Scenario, which also incorporates two other crucial elements of the Sustainable Development agenda: cleaner air and universal access to energy, in addition to climate targets.
In the IEA’s view, these elements are profoundly interconnected aspects of global energy transitions. The Sustainable Development Scenario is one of the very few deep decarbonisation scenarios that considers all of them in detail and provides a pathway that achieves them simultaneously, along with detailed attention to the security and affordability of energy supply. In our view, no vision of a sustainable energy world can be considered complete if parts of the global population do not have access to modern energy.
Another new feature of this year’s WEO is that the horizon for the Sustainable Development Scenario is extended by a decade to 2050. This has little impact on achieving modern energy for all, both for electricity and clean cooking. That goal is reached by 2030 in this scenario. But it provides a clearer view on how dramatic improvements in air quality reduce pollution-related premature deaths. And it gives considerable additional clarity on how the scenario meets the Paris Agreement goal of holding the rise in global temperatures to “well below 2°C … and pursuing efforts to limit [it] to 1.5°C.”
The Sustainable Development Scenario models a rapid and deep transformation of the global energy sector. It is consistent with all the “net zero” goals contemplated today being reached on schedule and in full. The technology learning and policy momentum that they generate means that they become the leading edge of a much broader worldwide effort, bringing global energy-related CO2 emissions down sharply to less than 10 billion tonnes by 2050, on track for global net zero by 2070.
This means that the Sustainable Development Scenario is “likely” (with 66% probability) to limit the rise in the average global temperature to 1.8 °C, which is broadly equivalent to a 50% probability of 1.65 °C stabilisation. These outcomes are achieved without any recourse to net negative emissions.
How does this scenario relate to the pursuit of a 1.5 °C outcome? For one answer to this question, we turned to the IPCC Special Report on 1.5 °C. Almost all the 1.5 °C scenarios assessed by the IPCC (88 out of 90) assume some level of net negative emissions. A level of net negative emissions significantly smaller than that used in most scenarios assessed by the IPCC would provide the Sustainable Development Scenario with a 50% probability of limiting the rise in global temperatures to 1.5°C.
However, as we have pointed out in the past, there are reasons to limit reliance on early-stage technologies for which future rates of deployment are highly uncertain. That is why the Outlook has always emphasised the importance of early policy action. That is also why, in the WEO-2019, we explore what it would take to achieve stabilisation at 1.5 °C with a 50% probability without net negative emissions.
Two different types of scenario make a powerful mix
The World Energy Outlook incorporates two different approaches to scenario design. The first defines a set of starting conditions and sees where they lead; the Stated Policies Scenario and the Current Policies Scenario are of this type.
The second approach does the opposite, defining a set of ambitious future outcomes and then working out how they can be achieved: this is the principle underlying the Sustainable Development Scenario.
Each of these approaches, on its own, offers powerful insights. In combination, they provide a broad perspective not just on the energy and climate challenges that we face today, but on what can be done to address them.
*Tim Gould, Head of Division for Energy Supply Outlooks and Investment.
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