Executive Summary

The COVID-19 pandemic is one of the most severe economic and energy shocks in modern history. On top of the massive disruptions to business, mobility, and everyday life, there clearly will be longer-lasting implications for the energy transition away from fossil fuels. While the shocks from the pandemic are leading to reductions in fossil fuel consumption and emissions, they will not be enough to put the world on a path to meet 2 degree global warming target, nor bring forward peak oil demand, nor drive coal consumption to near zero.

To achieve the targets under the Paris Agreement and limit global climate change, the energy transition will need to include a mosaic of solutions beyond just renewables and fossil fuel demand destruction: Hydrogen, carbon capture utilization and storage, and biofuels are all likely to play roles in decarbonizing the interconnected global energy system. Recent announcements from policymakers, leading energy companies, and end users illustrate the many kinds of climate solutions. While we continue to regularly publish our views and outlooks on all of the key pathways comprising the decarbonization mosaic, this report focuses on the impact of the COVID-19 pandemic on trends in the fossil fuels and renewables sectors.

S&P Global Ratings continues to expect global GDP to contract 3.8% in 2020, according to our latest forecast from June, worse than the 2.4% contraction in our April forecast, mainly due to a deeper, longer hit to emerging markets, led by India. Even if we see a reasonably strong recovery in GDP over 2021-2023, we expect approximately $5 trillion a year of lost economic output compared to our pre-COVID-19 forecast.

The magnitude and orientation of recovery and stimulus policies will shape GDP growth, but also the relative growth and type of energy consumption. Regionally, there are stark differences in the "greenness" of stimulus packages. The EU is clearly skewing stimulus policies to reinforce its wider commitment to working against climate change. While U.S. stimulus policies have been agnostic about clean energy to date, the U.S. presidential election represents a drastic change in course if former Vice President Joe Biden wins. China's new stimulus package is reliant on debt-financed infrastructure investments, many of which are energy intensive to construct and to operate for decades to come. China also loosened restrictions on new coal-fired power plants, partly due a greater focus on energy security, but this should be seen alongside a recent bold commitment by President Xi for China to become carbon neutral by 2060.

Of all sources of primary energy, COVID-19 is having the greatest impact on oil so far this year,  due to its pre-eminence as a feedstock for land, air, and sea transport fuels. We expect global oil demand to decline by 8.7 million b/d (down 8.4%) from the pre-COVID forecast, wiping out six years of growth. Reductions to industry and power generation, particularly in developing nations, are likely to reduce coal demand by the equivalent of 4.4 million b/d of oil (down 5.7%). Natural gas demand, due to its prevalence as a heating fuel, took less of a hit during lockdowns, declining by only 2.1 million b/d (down 3.0%) of oil equivalent from the pre-COVID forecast. Delays in renewables installations (not project cancelations) in key markets are likely to reduce renewable energy production by less than 1.0 million b/d of oil equivalent (down 3.6%) in 2020.

Out to 2030, demand for natural gas in our forecast saw the largest downward revision,  as COVID-19 exposed a long-standing structural weakness in gas demand: Its growth potential is linked to the growth of overall demand, particularly electricity demand, though limited by demand for coal and renewables. With relatively small reductions to the outlooks for coal and renewables, gas absorbed the brunt of the decline in overall energy demand. To put this another way, the proverbial bridge that natural gas has played in the energy transition has become shorter and narrower. Even so, this does not mean that global gas demand will peak over the next 10-20 years, as growth continues to stem from China, India, and the Middle East. Gas producers are focused on such new markets, with Russia's Gazprom aiming to increase exports to China to 130 billion cubic meters a year. For oil, the greater prevalence of working from home and less business travel, coupled with weaker forecast GDP, has reduced the 2030 outlook for oil demand by 1.9 million b/d (down 1.6%) compared to the pre-COVID forecast. This reduction would have been larger were it not for a downward revision to electric vehicle penetration linked with weaker oil price expectations. While the outlook for coal demand was also reduced, the adjustment was relatively small, at just 0.3 million b/d of oil equivalent (down 0.5%), as the drivers of coal demand remain largely intact--power generation and industry in developing nations, particularly China. It should be noted that S&P Global Platts Analytics projected declining coal demand over the long term even before COVID-19, driven by reductions in the U.S., Europe, and elsewhere in the OECD. For wind and solar, supportive policies and cost reductions will continue despite COVID-19, and the outlook for renewables output was reduced by only 1.2%.

From a credit perspective, we have seen a larger number and more severe rating downgrades among oil and gas companies than during the 2014-2015 oil price collapse.  This not only reflects the unprecedented drops in demand and prices caused by lockdowns, but equally the tighter financial headroom many players had going into this crisis, as well as the headwinds the sector has been facing in terms of energy transition uncertainty and declining profitability. The U.S. power and utility sector has been largely resilient, but companies need to adjust strategies. This is because we project gas-fired generation to peak in 2020 in view of the continuous shift to renewables, which could accelerate in case of a Biden win and his plan for a carbon-free power sector in 2035. In Europe, green regulations are unlikely to support gas in the long term, which have started to weigh on the regulatory returns of gas grids in Europe, even if the fuel will remain important over the next decade given coal and nuclear phaseouts, especially in Germany.

As for renewables players, we see the continued strong policy support globally as an overriding credit strength, but not all lights are green.  The increased cost competitiveness of renewables, the rising system costs as a result of substantial renewable subsidies of the past, and potentially more budgetary constraints caused by the COVID-19 crisis are contributing to decreasing subsidies and tax credits, as seen in Europe and the U.S. In China, renewable projects will even have to compete at grid-parity prices starting in 2021. However, the key to such cost competitiveness is the ability of projects to continue attracting low-cost funding. Investor appetite remains strong but still requires long-term price visibility in terms of power price agreements (PPAs) or fixed-price auctions, both of which are less available. COVID-19 has also triggered a cloudier outlook for long-term power and gas prices. Finally, the increasing role of renewables in the power mix has underscored the risks of curtailments and intermittency, evidenced by recent rolling blackouts in California. At the same time, as more conventional generating capacity is retired, especially in the U.S. and Europe, more batteries will be needed to boost flexibility needs or policies will need to plan for keeping more peaking capacity online. Hydrogen's potential role as a longer-duration storage and power load management solution can move the renewables and power industry further along in the energy transition.

Utility incumbents may be best placed to manage rising renewable market risks, but big oil could equally make inroads.  For investors, we see rising market risks and compressed returns given stiff competition and the phasing out of subsidies in many cases. This, together with the economic uncertainty COVID-19 brings, means that larger energy players, with strong balance sheets and vertical integration--with dispatchable generation and natural hedging through retail--may be better positioned to consolidate the industry. The oil majors could play a role given their size, existing gas and power trading, downstream fuel retail operations, and/or offshore expertise. BP has indicated it expects to employ by 2025 as much as 20% of its capital in transition businesses, including low carbon. Given highly competitive asset prices for renewables and power retail opportunities, we expect the oil majors to face a long and challenging journey along the energy transition.

The Energy Transition: Does COVID-19 Bend The Emissions Curve To Two Degrees?

The COVID-19 pandemic has not only altered energy supply, demand, and prices in the near term, but also to some extent their long-term trajectories. Looking just at demand, the repercussions from the pandemic have changed three primary drivers: macroeconomics, behaviors, and policy. As a result, S&P Global Platts Analytics has reduced the outlook for CO2 emissions by 27.5 gigatons (GT) over 2020-2050. However, this represents only a minor step in the direction needed to meet the 2 degree target under the Paris climate accord, which would require more than 10 times that reduction over the period. Nevertheless, the emissions reduction achieved in 2020 is equivalent to the decline required by 2027 in a 2 degree scenario, illustrating that sizable emissions reductions are possible.

Quantifying the impact of COVID-19 on energy demand and its associated emissions in both the short and long term requires a three-pronged approach, examining macroeconomics, behaviors, and policies individually and holistically.

Macroeconomics

The first prong is to quantify the economic impact of the virus on overall energy demand. The COVID-19 pandemic has certainly shocked global macroeconomic growth in 2020 and 2021, but there will likely be longer-lasting implications. Platts Analytics projects that even beyond the 2020-2021 macro shock, long-term global GDP has been lowered by approximately $5 trillion on a purchasing power parity basis. The relationship between global GDP and primary energy demand is directly correlated, although the elasticity of demand relative to GDP has weakened over the past decade due to efficiency gains and the shift in many economies to less energy-intensive industries. However, even with weaker demand elasticity, a $5 trillion loss to global GDP should equate to a loss of energy demand on the order of 7-9 million barrels of oil equivalent per day. If this amount of demand loss was completely made up of coal, it would represent 1.3-1.8 GT of CO2 emissions; for oil it would represent 0.8-1.1 GT of CO2 emissions, and for natural gas, it would represent 0.7-0.9 GT of CO2 emissions. This range represents roughly 2%-5% of total annual energy combustion emissions.

Behavior

The second prong is to determine and quantify how COVID-19 could permanently modify behaviors. For the most part, such behaviors are centered on transportation. The lockdowns prompted some rethinking about the need and desire for travel by individuals and organizations. As long as there are fears of coronavirus transmission, there will be reductions in demand for air travel for business and pleasure, and many business will either mandate or allow working from home to continue. However, even if or when these fears subside, demand for travel will not return to its previous state. For air travel, businesses are have been forced to curb travel, opting for online meetings, conferences, and other virtual engagements, with many already signaling that these changes will continue after the pandemic to some degree. The reduction in business travel has yielded considerable costs savings, and some businesses will permanently reduce travel for employees. According to a recent survey conducted by 451 Research, the emerging technology research unit of S&P Global Market Intelligence, 23% of enterprises surveyed indicated they expected travel restrictions to remain in place over the long term or permanently. This would have large knock-on effects on demand for road and air transportation fuels. We project that even a modest reduction in demand for air travel could result in 1.0-1.5 million barrels per day of lower oil demand over the long term, equivalent to 14%-21% of aviation sector oil demand in 2019 (see the Platts Analytics report, "Quantifying Risk: How Much COVID-19 Could Change Consumer Behaviors And Impact Long-Term Oil Demand.")

Many companies have also identified potentially long-lasting cost savings of allowing employees to work from home, particularly if business activities were largely able to continue during lockdown conditions with the aid of telecommunications tools. The 451 Research survey showed that two-thirds of surveyed organizations expect some level of expanded working from home policies to remain in place over the long term. However, separate surveys show that less than 20% of office workers want fully remote working arrangements, while nearly three-quarters of office employees do not want to go back to the office five days a week. This suggests a desire for arrangements that allow part-time working from home. Platts Analytics projects that the equivalent of 5% of the OECD's workforce could manage to work from home permanently with a moderate change in behavior, which would reduce demand for petroleum-based road transportation fuels by an additional 1.0 million-1.5 million barrels per day over the long term, equivalent to 2%-3% of petroleum-based road fuel demand in 2019.

Not all changes to behavior will be negative for demand. Aversion to public transportation in favor of private transportation could increase demand for gasoline and diesel. A slowdown in electric vehicle (EV) penetration because of low oil prices or reduced household purchasing power could similarly increase oil demand, offsetting some of the negative demand dynamics of COVID-19. However, the adoption of EVs is influenced by a number of factors ranging from fuel prices to governmental subsidies and resale value.

While changes in travel behavior typically do not meaningfully affect natural gas or coal demand because those fuels are not commonly used in the transportation sector, there will likely be second-order effects. For example, if there is less travel in general, the hospitality sector would shrink, reducing the need to heat/cool, power, and fuel hotels and restaurants. On the flip side, a greater prevalence of working from home would shift heating demand from the generally more efficient commercial sector to the generally less efficient residential sector, likely resulting in a net increase in demand for heating fuels like natural gas and oil.

Policy

The third prong is to determine and quantify how COVID-19 could alter policies that affect energy demand. Predicting policy changes is notoriously difficult to do with any degree of accuracy, and there is a wide range of potential outcomes depending on the severity of policy effectiveness. However, there have already been signs of how some countries may react to COVID-19. European policymakers have signaled their intent to skew stimulus packages toward green initiatives, such as a greater push for electric vehicles, renewables, and hydrogen. These policies are also seen as an additional impetus for Europe's wider ambition to achieve net zero carbon emissions by 2050, an aggressive goal given Europe emitted about 3.8 GT of CO2 in 2019 (gross basis) according to a Platts Analytics analysis.

On the other side of the Atlantic, the U.S. has not provided any support for green initiatives in stimulus measures to date. The U.S. presidential and congressional elections in 2020 offer a stark dichotomy of how COVID-19 policies could evolve. President Donald Trump's stance on environmental policies over his administration to date signal that he would not support green initiatives in general and as part of stimulus packages in particular. However, the Democratic Party nominee for president, former Vice President Joe Biden, has released a series of plans, called "Build Back Better," which includes an aggressive goal of carbon-free power generation by 2035. By comparison, the U.S. power sector emitted 1.6 GT of CO2 in 2019, and Platts Analytics projects 2035 emissions in the sector will be 0.9 GT.

In Asia, policy announcements in reaction to COVID-19 have been mixed. South Korea announced a draft plan, dubbed "South Korea's Green New Deal," designed to stimulate its economy and drive emissions to net zero by 2050. It should be noted that this plan is not currently enshrined into law, and environmentalists claim the deal is neither specific nor aggressive enough in the short term to move toward net zero. While China announced energy efficiency goals as part of a stimulus package, it also rolled back regulations on coal plants. Other countries in Asia, ranging from Japan to Malaysia and Myanmar, have announced new renewable projects nominally in response to COVID-19, although it is possible these projects would have proceeded in absence of the pandemic.

Adding up the three net zero policy targets that have risen in prominence in the wake of COVID-19--from the EU, South Korea, and from Mr. Biden--yields approximately 6 GT of gross CO2 emissions in 2019, or 17% of total energy combustion emissions. While policy targets, particularly ambitious ones such as net zero, do not often come to complete fruition, implementation of strong policies in these countries could curtail emissions by several GT, according to the projections in our outlook. Currently, Platts Analytics' World Energy Demand model projects gross emissions from these areas and sectors will decline to under 4 GT by 2050 in its Most Likely Case outlook.

The Energy Transition: The Effect Of COVID-19 Economic Recovery Policies

The COVID-19 pandemic has taken a heavy economic toll on the global economy. We forecast global GDP will contract by 3.8% this year, compared with a 0.1% contraction in the 2009 global financial crisis. While all major economies reacted in the short term with large monetary stimulus, not all will accelerate the energy transition as a consequence. In the EU, which targets a net-zero carbon economy by 2050, policy support is significantly pushing renewables' growth in Europe. The recovery fund approved by the European Commission in July 2020 dedicated €225 billion to the energy transition, to be invested in the next three years. However, China's transition to a low-energy-intensity economy, fueled increasingly by renewables, is likely to stall in 2020 and 2021 as policy stimulus ripples through the economy. In India, while the plunge in activity will reduce energy use, policymakers are unlikely to focus on the energy transition until the economy regains its footing. The U.S. federal government, meanwhile, has not provided any new support for green initiatives in stimulus measures to date beyond the current tax incentives. State mandates and ESG concerns continue to be the main impetus of U.S. installations so far, but the outcome of the November elections will be clearly a pivotal moment for policy decisions on climate change.

EU Countries Will Use Recovery Plans To Accelerate Toward Carbon Neutrality

The European economy has experienced its worst recession since World War II this year because of measures to contain the spread of COVID-19. Eurozone GDP was down 15% in the second quarter of 2020 year on year. The large scale of the crisis triggered unprecedented fiscal and monetary policy support. Governments are now focusing their efforts on speeding up the recovery through fiscal stimulus. And given the challenges of climate change, they have identified the energy transition as a key area to inject support.

Already before the crisis, EU countries had agreed to speed up the fight against climate change with the Green Deal set of policy initiatives aiming to make Europe climate-neutral by 2050, as well as the Green Taxonomy initiative. In spite of some pushback against environmental regulation from industries at the onset of the crisis, the EU now intends to use its post-pandemic recovery plan to reinforce its fight against climate change (see "The EU's Drive For Carbon Neutrality By 2050 Is Undeterred By COVID-19," published April 29, 2020, on RatingsDirect). In this plan, agreed in July, EU countries pledged that 30% of the Next Generation EU Fund's €750 billion fiscal plan and the EU multiannual budget would target climate-friendly projects. This is more than the 25% agreed in the Green Deal in January. This also means there are now more funds allocated to mitigating climate risk than before the crisis. The additional €225 billion coming from the recovery plan corresponds to 1.7% of 2019 EU GDP.

At the time of writing, most governments have yet to disclose the details of their fiscal stimulus, but from what has been announced so far, it seems that national governments will go beyond what the EU is asking in terms of greening the economy. Both France and Germany are allocating more resources to the ecological transition than will be made available to them through the EU's Next Generation recovery fund. France is planning to spend €28 billion of its €100 billion on mitigating climate risk, Germany around €22 billion of its €130 billion (see table 1).

Table 1

Climate-Related Fiscal Stimulus At The National Level
(Bil. €)	Germany	France
Transport	10.25	11
Energy and green technologies	9.02	9
of which hydrogen	9	2
Buildings	2	6.7
Other	0.3	1.2
Total	21.6	27.9
Percentage of total fiscal stimulus	16.6	27.9
Source: S&P Global Ratings.

Although not all climate-friendly fiscal stimulus will go to the energy transition, it is one of the three main pillars of the EU climate-friendly investment strategy, alongside building improvements and transportation. This is because in order to reach the goal of carbon neutrality by 2050, EU countries are having to move to cleaner energy sources. Countries that are more reliant on coal for energy or generally produce less output per unit of CO2, such as Poland and the Czech Republic, are likely to spend more of climate-friendly investments in the energy transition. This difference is already visible between France and Germany, with France putting one-third of its climate-related investments into the energy transition and Germany one-half.

A key feature of fiscal stimulus during crisis times is its multiplier effect, which is larger than during normal times. In other words, every euro invested by governments in the energy transition will stimulate investments from the private sector in this domain. According to research by the IMF, this fiscal multiplier is around 2x after one year and about 3x after five years for the aggregate economy in the eurozone. Germany's and France's fiscal plans assume that around one-third of the climate-friendly EU investments will be invested to support the energy transition (around €75 billion). With a multiplier effect of 3x in five years, private funds attracted from public investments in greener energy would add up to €150 billion, giving significant support to the energy transition in the EU.

In The U.S., A Green Strategy For Recovery Is In The Balance

The impact of the COVID-19 pandemic in the U.S. has been profound, with the number of cases topping over 6 million. More than one-half of the 22.2 million workers who lost their jobs remain unemployed, and the unemployment rate is over twice its pre-pandemic rate. Second-quarter GDP plunged by 31.7%, the largest drop since 1947. While the number of reported cases is lower than its July peak, regional hotspots still persist in some areas, such as the South and Midwest states. While we expect the U.S. economy to grow in the third quarter, we don't expect it will reach pre-crisis GDP levels until fourth-quarter 2021. In environmental terms, the pandemic will cause the largest absolute reduction in CO2 emissions. Yet, absent policies that encourage green solutions, these emissions are set to rise again as the economy recovers. As such, the spotlight is on Washington in this pivotal election year, where economic recovery, job creation, and climate change are key topics of focus.

Green-flavored recovery policies as a response both to economic crisis and climate change concerns are not new for the U.S. In the midst of the Great Recession and public concerns foreshadowing the 2009 United Nations Framework Convention on Climate Change, then-President Barack Obama signed the American Recovery and Reinvestment Act (ARRA) into law in February 2009. The stimulus was estimated at $830 billion, of which $90 billion was allocated to environmental investments such as renewables, energy efficiency, and green infrastructure.

On the one hand, such policies have been shown to provide economic benefits. The International Energy Agency report "Green Stimulus after the 2008 crisis: Learning from successes and failures," published in June 2020, noted that "evidence suggests that the macroeconomic benefit of green stimulus programs ranged between 0.1% and 0.5% of GDP for around two years, depending on the size of the stimulus program". Furthermore, while accounting for only about 10% of the ARRA's funding, the tax policies and grants provided under the act were instrumental in accelerating the deployment of photovoltaic (PV) solar and onshore wind, vital for the overall energy transition.

On the other hand, given the capital-intensive nature of the energy sector, there is some debate on the trade-off between near-term GDP boosts and near-term job growth. Priorities in Washington this time around may center more on near-term job creation, which could drive stimulus funds to support sectors like health care and transportation. Furthermore, the ARRA had some unintended consequences in that Chinese manufacturers scaled up solar wafer and module manufacturing in response to strong policy-driven pipelines, which in turn lowered prices. This led to closures of some U.S. PV businesses, which were unable to compete.

There are stark contrasts between the two candidates in the forthcoming presidential elections in terms of infrastructure policy and stimulus proposals. In July, Democrat Joe Biden updated his existing climate plan, calling for $2 trillion in spending for sustainable infrastructure over four years, including roadways, buildings, broadband, and clean energy. While this spending would boost economic output, the implementation of emissions and clean energy standards to complement the spending would be more effective in reducing emissions than spending alone. The plan advocates for standards that target a carbon-free power sector by 2035 and net-zero emissions for all new commercial buildings by 2030. Federal legislation would be required to enact these specific policies and a simple 51-seat Democratic majority in the Senate will likely not be enough for some of Biden's more ambitious proposals. Democratic senators who represent carbon-intensive states might be more reluctant to support legislation that incentivizes clean energy over traditional fossil fuels. The larger the majority, the easier time his administration will have enacting its platform.

In the case of a Trump second term, the U.S. would expect a continued push for tax cuts and deregulation alongside further attempts to streamline the infrastructure permitting process. However, a platform consisting mainly of tax breaks and deregulation may not necessarily be enough to overturn the decline in infrastructure investments in general--both within the energy and non-energy sectors--because tax equity availability has become scarce.

Post-COVID Recovery In China Means More Energy, More Carbon For Now

The two economies that will shape the way that Asia-Pacific's COVID-19 recovery affects the global energy transition are China and India. We expect China's transition to a low-energy-intensity economy, fueled increasingly by renewables, to stall in 2020 and 2021 as policy stimulus ripples through the economy. Still, President Xi has recently signaled a bold intention for China to become carbon neutral by 2060. India's economy has been hit by an enormous shock that will impose large, permanent damage. While the plunge in activity will reduce energy use, policymakers are unlikely to focus on energy transition until the economy regains its footing.

Focusing on China, we expect that the energy intensity of China's economy will be little changed this year compared to 2019. Based on what we know for the first eight months of the year, total consumption of energy has edged higher compared with the same period in 2019. This compares with our estimate of real GDP, which is about 1% lower for the same period, causing the ratio of energy to GDP to edge up. Official estimates also suggest a slight uptick in energy intensity.

China's progress toward an energy mix less reliant on fossil fuels has also stalled since COVID-19 struck. Renewables are contributing more to power generation, aided by exceptionally heavy rainfall and hydro and the rush for installation of wind and solar power capacities in the run-up to grid parity. However, rising industrial energy use offsets this effect. This is especially true for steel firms, which are heavy coal users.

China's policy stimulus throws trend off course

The stimulus of 2020 is not an exact replay of 2009--it is certainly smaller--but there are echoes of the past. The most important is the reliance on debt-financed infrastructure investment to support the economy. Investment in roads, rail, and airports consumes a lot of steel, cement, and bulk commodities, which means more energy use, especially from fossil fuels.

S&P Global Platts estimates that new airport and railway projects approved this year, combined with projects approved in 2016-2019 which are now proceeding as access to funding has been eased this year, should contribute to about 23 million metric tons of Chinese steel demand in 2020--an almost one-quarter rise on 2019. Overall infrastructure investment, including investment in power generation, will be up by about two percentage points of GDP compared with the five-year average through 2019.

This infrastructure push, together with a buoyant post-COVID property market and a pick-up in auto production, has meant that steel, other metals, and raw materials have led the manufacturing recovery. Industry accounts for more than 40% of total coal consumption, including coal used in electricity generation. Steel and non-metallic minerals production alone account for about 15%, where it is mainly used as a fuel and reductant in cement kilns and blast furnaces.

Coal comes back

China is edging back towards coal. In 2014, during a time of overcapacity and large financial losses in China's coal sector, the National Energy Agency (NEA) began restricting local governments from adding to new coal capacity over a three-year horizon. The NEA has eased these restrictions for the past three years and again in 2020. Partly in response, local governments are approving more coal power projects: about 19.7 gigawatt (GW) of capacity was approved in first-half 2020, the highest rate in recent years.

The National Development and Reform Commission (NDRC), an economic planning body, and the NEA still aim to cap total installed coal power capacity at 1,100GW by the end of 2020. Given new capacity coming on stream, this would mean shuttering inefficient capacity of 7.33GW nationwide this year, a target which is lower than the 8.66GW set in 2019. It's uncertain if the regulator may lift the cap on coal power, as suggested by the industry association, to about 1,300GW by 2030 to meet demand.

It is not all coal, though. In early September, the State Council approved two new nuclear reactors that should be ready in 2025 and 2026. Investments in renewable energy, especially wind power, also remain strong in the run-up to the rollout of grid-price parity, which will remove subsidies for utility-type solar and onshore wind-power projects from 2021. China has been gradually phasing out the subsidies for renewables after robust growth during the 13th five-year plan. In the first half of 2020, investment in the generation sector grew 73% year on year, driven by a 190% surge in wind power. Wind accounts for just over 6% of power generation so far in 2020.

New infrastructure holds promise in getting China back on track

China has committed to becoming carbon neutral by 2060. We expect the plan to call for more investment in infrastructure to eventually help in lowering energy intensity and reduce carbon emissions. These investments include high-speed rail, data centers, and rapid 5G rollout, all of which may foster more efficient private transport and more digitalization. While this will boost demand for electricity, a rising share of renewables in power generation should result in less fossil fuel consumption in the power sector. So far this year, 25 province-level regions, accounting for over 90% of China's GDP, have included new infrastructure in their government work reports for 2020, although it is likely to remain a small share of overall infrastructure spending.

Energy security over energy transition?

China's strategic response to less predictable geopolitics will move energy security near the top of the policy agenda. China imports over 70% and 43% of its crude oil and natural gas, respectively. About 90% of oil imports arrive by sea and much of this traverses through the potential chokepoint of the Malacca Strait and the South China Sea. Digitalization means more electricity demand and coal is a reliable and cheap source of primary energy for power generation. Indeed, China is rich in coal with about 13% of global reserves. We expect policies promoting the use of more renewables, but it's too early to count coal out.

Warnings signs abound that the energy transition has stalled in the country, but this must be considered alongside its new commitment to achieve carbon neutrality in 2060. We will learn more when the 14th five-year plan is released in March 2021.

The Energy Transition: COVID-19 And Peak Oil Demand

One Of The Biggest Disrupters Since Birth Of The Oil Industry

Petroleum's pre-eminence as a land, air, and marine transport fuel is seeing oil consumption drop the most of all primary energy sources amid the global economic downturn that started this year. The unprecedented collapse in worldwide mobility as a result of lockdowns and travel restrictions in March and April 2020 slashed oil demand by over 20 million b/d, or 20% of total demand. We expect global oil demand for 2020 as a whole to decline by 8.1 million b/d, wiping out six years of growth. We expect about 75% or 6.3 million b/d of demand to come back in 2021.

The unprecedented cut to demand was met with an unprecedented cut to supply. After initial disagreement and delay, OPEC+ implemented decisive cuts, which allowed the market to start rebalancing and restored some confidence, although maintaining discipline may not be easy for the cartel. Producers inside and outside of OPEC+, facing their second crisis in five years, responded by slashing capex, costs, and shareholder returns.

Not all adjustments to demand will be negative

While the global oil market will rebound considerably as the world economy recovers and lockdowns ease, the disruptions to both global oil demand and supply will persist far after the pandemic has ended, with considerable implications for the energy transition. For demand, individuals and businesses forced to reduce travel during lockdowns have identified potential long-lasting cost savings that will both blunt the recovery in consumption and reduce long-term demand. Many businesses have made working from home arrangements permanent to reduce real estate needs and costs, and have signaled that business travel will be reduced for the foreseeable future as well. The recession also raised inequality, with a shift of part of the middle class into poverty, which has triggered a drop in demand on its own, perhaps as high as 400,000 b/d.

Partly offsetting these negative impacts, are the following: There could be an aversion to public transportation in favor of personal vehicles if fears of virus transmission persist. Additionally, weaker oil prices make electric vehicles (EVs) less competitive than internal combustion engine vehicles and will slow their penetration relative to the pre-COVID forecast. More broadly, a weaker oil price framework will insulate oil demand from competitive threats, including a drive for efficiency improvements. And finally, there is the elasticity of demand, as a $10 a barrel lower oil price could raise oil consumption by 2.5-3.5 million b/d.

While S&P Global Platts Analytics projects that 2021 global oil demand will regain approximately 75% of the 2020 demand loss, we do not project overall consumption to return to pre-COVID-19 levels until late 2022 and believe long-term demand for oil has been permanently altered. Some sectors, most notably aviation, will take even longer to recover to pre-COVID-19 levels. The reduction in demand was driven by both our revised weaker macroeconomic outlook, and the assumption of a modest change in behaviors listed above. The weaker oil demand forecast averages out to a drop of 2.5 million b/d over 2020-2050. However, while the outlook for global oil demand has shifted lower, the trajectory of year-to-year growth and the projected peak in oil demand near 2040 remains similar to the pre-COVID-19 outlook.

On the supply side, cuts to capital expenditures and specific project delays will lead to a reduction in non-OPEC (non-shale) production well into the mid-2020s and have even longer-lasting repercussions if producers require higher price signals relative to project breakevens to commit to new supply. We expect the combination of COVID-19 and the oil price collapse to halve growth in non-OPEC supply (outside of the U.S. and Russia). For U.S. shale, the reduction in the rig count and overall activity, coupled with the relatively steep decline rates of shale wells, will result in a slow recovery of output, and S&P Global Platts Analytics projects that U.S. crude and condensate supply will not return to 2019 levels until late 2023 or early 2024. Even after this period, weaker demand and price projections have reduced the outlook for U.S. shale by an average of 900,000 b/d over 2025-2040. For OPEC+, the reduction in supply in 2020 was greater than that of non-OPEC, although S&P Global Platts Analytics projects that OPEC+ can bring supply back to the market when demand and price dictate than non-OPEC can. This flexibility will advantageous because the recovery of oil demand and non-OPEC oil supply will almost assuredly not be synchronized. However, even the forecast of OPEC+ output was reduced from the pre-COVID-19 forecast due to the severity of the projected demand decline, but by a relatively small amount compared to non-OPEC.

COVID-19 is a significant, but not transformative event

For both long-term global oil demand and supply, the impact of COVID-19 is a decided step down, but not a step change--that is, not enough to alter the trajectory of the oil market enough to meaningfully bring forward the peak in oil demand, or align oil sector CO2 emissions with a 2-degree warming target. However, the global economy and oil market are still reeling from the pandemic, and it's unclear how much behavior and policy will change in response. In an attempt to address these risks, S&P Global Platts Analytics undertook a sensitivity analysis to determine what potential changes to consumer behavior and capital investment would force oil demand to perpetually remain below the 2019 peak.

As opposed to S&P Global Platts Analytics' Most Likely Case that concludes that up to 3 million b/d of long-term oil demand is at risk due to changes in discretionary travel, this peak demand sensitivity makes harsher assumptions on discretionary travel such as full working-from-home stickiness. Specifically this assumes that remote work becomes the status quo following the pandemic, representing up to 25% of vehicle miles traveled in the U.S. (and a similar impact outside of the U.S.). A similar severe reduction in aviation demand was adopted in this sensitivity, with a baseline rate of over 4% a year halving to just over 2% a year, implying that the world will only approach pre-pandemic levels of air travel by 2030 (whereas our baseline assumptions assumes so by 2024).

Downward pressures on oil demand as a result of changes to capital investment could persist in a post-pandemic world across several sectors, including marine bunkers, industrial demand (manufacturing), chemicals, and even commercial road transport. We project oil demand in marine bunkers to grow steadily through 2040 in our analysis of supply-demand balances due to more rapid economic growth and, in turn, international trade. In this peak demand sensitivity, S&P Global Platts Analytics projects that anti-globalization trends will accelerate, modeled as a 50% reduction in the forecasted globalization index from 2020-2025 versus our Most Likely Case. This sensitivity also assumes reshoring of supply chains away from countries where oil use is high in the industrial sector, specifically China, Saudi Arabia, and Mexico. Finally, in terms of capital investment decisions, evolving shopping patterns could have a material change on commercial road fleets. As part of a market-driven response to the complete shift away from brick-and-mortar retail to online shopping after 2020, delivery fleet operators could seek to electrify delivery trucks and vans, building upon the landmark partnership between Amazon and commercial EV manufacturer Rivian. Taken together, all of these modeled trends point to a world that could see peak oil demand by 2035 instead of 2040. When excluding petrochemical feedstocks, that is, refined products, demand could peak as early as 2025 (versus 2035 in the base case). However, we note that this scenario hinges primarily on changes to market behavior that are not necessarily market driven, but are rather discretionary or related to risk aversion.

Oil & Gas Companies Are Bracing For A Somewhat Different Future

Prior to COVID-19, the inevitability of the global energy transition represented a disruptive future for oil and gas companies.  COVID-19, in many aspects, may have brought this future forward. Indeed, the pandemic created the second severe sector downturn in five years and the third in 12 years. Not surprisingly, default activity has spiked again.

While COVID-19 will not abruptly usher in a new world order, it has forced oil and gas companies to reassess future investments and price assumptions, accepting that weaker demand is likely to keep oil prices lower over the long term. The latter has caused some majors to report large write-downs to their assets, due to numerous projects being no longer commercially viable under their revised prices. Because of this, combined with mounting ESG concerns, oil majors could reduce investments in traditional oil projects in favor of clean energy investments, in 2020 and beyond. This is one of the shifts in BP's revised strategy.

We believe cash flow from oil and gas companies may be even less certain in the coming decades than in the past 10 or 20 years.   Although S&P Global Ratings factors in a price recovery to a $50-$55/bbl range in 2023 on the back of supply-demand rebalancing, COVID-19 has further underscored the increased risk of behavioral change causing a lower-for-longer oil price scenario, such as the one presented above by S&P Global Platts Analytics. Even if we still see such a stress scenario as unlikely, it is one of several factors weighing on our business risk assessments of oil and gas majors. (See also "Write-Downs, While Eye-Catching, Are Not The Largest Issue Facing Oil And Gas Supermajors," Aug. 3, 2020).

A prevailing thought among analysts is that lower oil prices caused by the pandemic could test oil companies' commitment to renewable energy investment given the strain on budgets.   However, cuts to renewable energy by the largest players have been nominal, especially outside the U.S. Indeed, several firms like Total and Eni have reaffirmed their commitments to renewable investment and as a percentage of total spending, renewable spending actually increased. We recognize that renewables remain a modest percentage of overall budgets, but all major oil companies have slashed capital expenditure plans and announced severe cost-cutting measures. In some cases, majors like Shell, BP, and Equinor have slashed dividends that had long been considered sacrosanct.

Trends in investor sentiment, ESG-related pressures, and policy developments will likely only increase after the pandemic, and influence strategies and longer-term investment decisions in renewables.   Over the last six years, the oil and gas industry has been one of the worst-performing sectors in the S&P 500. In response, oil companies have been forced to cut their capital spending budgets to improve cash flow and deliver higher returns to an investment community that has stopped clamoring for production growth and grown weary of volatile and weak fossil fuel prices. As for public policies, the EU's 2050 net-zero carbon emission policy partly explains why European majors are further along the renewable investment path than U.S majors. BP has explicitly signaled that as part of its new strategy, while hydrocarbon production will decline 40% to 1.5 million b/d of oil equivalent by 2030, its renewable power generation will increase 20 fold from 2.5 GW in 2019 and it will increase the number of EV charging points by nearly 10x to 70,000. The U.S. majors have made far less of an effort to move away from fossil fuel investment, in part because there has been very little incentive to do so from government. Nonetheless, this could potentially change after the November election if former Vice President Joe Biden were to win the presidency. He has pledged $2 trillion to eliminate all greenhouse gases from the electricity grid before 2035.

Investing in renewables is, however, a double-edge sword.   Ironically, reduced profits from oil and gas can make capital allocation to--historically lower-yielding--renewables a less dilutive prospect for group earnings. Still, for companies used to putative double-digit returns from oil and gas upstream projects, it remains a tough choice to invest in assets that are priced in an extremely competitive manner. We see generally only high single-digit returns, and often only achievable after adding significant financial leverage and increased debt-related risks--on or off the balance sheet. We believe indications of future returns are just that, but Shell has pointed to a 12%-14% as a range for renewable projects. BP has guided group return on adjusted capital employed (ROACE) increasing to 12%-14% in 2030 from 8.9% in 2019. This implies some value could be added through integration into other group businesses, compared with stand-alone renewable projects. The increasing size of renewable projects (notably offshore wind) and policy shifts to reduce subsidies or to shorten fixed-price protection may represent an opportunity for large, well-funded new entrants. At the same time, risks in merchant power should not be underestimated, notably when lacking a diversified generation mix or downstream integration. In some respects, BP's steps into solar two decades ago were just too early. This shows the difficulty of developing and delivering the right offering in the right place at the right time. It's fair to say that we don't see an immediate "new energy" replacement for the potential large value creation of a successful oil and gas appraisal.

Oil and gas companies might turn to testing other energy markets and business models at a manageable scale, that would provide diversification from fossil fuels and options with which to adapt to changes in energy scenarios.   These can include expanding gas and power trading operations and downstream integration into power retail operations. The latter is particular important to reduce the extreme volatility of power generation. Two examples in 2018 included Shell's purchase of First Utility in the U.K. and Total's acquisition of Direct Energie in France. Deploying EV recharging facilities to maintain traffic at retail sites is another adaptation. Clearly, the oil majors also have a competitive strength in offshore projects and execution of large projects, making offshore wind an attractive growth area. Finally, the development of carbon capture storage technology and related commercialization of hydrogen would support their gas business, but European policies strongly favor green hydrogen (generated through renewable electricity). Finally, the massive size and financial strength of the oil majors may position them best as future consolidators and leaders of a broader energy industry—not just as hydrocarbon players. Oil producers can make their production processes a bit greener and offset their Scope 1--and even Scope 3--emissions. But they need to become energy, not just oil and gas companies, if they want to really change their colors.

The Energy Transition: COVID-19 Undermines The Role Of Gas As A Bridge Fuel

The pandemic threatens the future of gas more than any other fossil fuel

Even though the COVID-19 pandemic has had less effect on the demand for gas than for any other fossil fuel in 2020, it threatens to have the most impact on gas over the next 10-20 years, reflected in the more than 9% reduction in our 2030 global gas demand outlook. Gas absorbed the brunt of the decline in overall energy demand after relatively small reductions to our coal and renewables outlooks.

The challenge will come from the legacy contribution of gas to global greenhouse gas (GHG) emissions and the growing commercial and policy-driven motivations that strive to skip, or at least accelerate, the role of gas as a transition fuel. China and India will remain the focal points for demand growth through the decade, while the U.S., Russia, and Qatar develop a global rivalry in terms of production growth.

While driving down the cost of delivering gas from the field to the burner tip has already proved to be a herculean task, the outlook also shows that price alone will not be enough to create growth. Alternative investments in renewables, hydrogen, and storage are challenging gas for the attention of capital. Environmental, social, and governance (ESG) issues add another layer of complexity and will shrink the pool of available capital until the industry makes the necessary investments to end flaring, venting, and leakage along the entire value chain.

Paradoxically, coal is likely to linger more in developing markets because of existing infrastructure and contractual commitments, security of supply considerations, and in some cases, price competitiveness. Upstream assistance from oil and natural gas liquids (NGLs) production to associated gas will partially alleviate concerns about the next generation of gas supply, although the outlook for oil and NGL demand has also diminished due to COVID-19.

Carving a path for demand growth will be gas producers' biggest challenge

Gas was already in a precarious position in the energy transition, and the COVID-19 pandemic only adds to this. No other fossil fuel holds the dual role of being part of the solution and part of the problem when it comes to meeting targets, ranging from compliance with ESG standards to climate goals.

Notwithstanding our downward revision to long-term gas demand, the expected rate of growth for natural gas remains stronger than for any other fossil fuel, and yet the outlook for gas is not rosy or without major risks. Gas supply potential and new reserve additions have piled up faster than all but the most aggressive scenarios for demand growth.

We believe that COVID-19 will perpetuate, if not slightly accelerate, a structural change for gas demand that has been apparent for the better part of a decade. Demand growth is slowing and reversing this trend will be difficult without major policy intervention.

The issue with gas is neither availability nor price, but demand

Gas supplies are plentiful in a region like North America, which has pushed down the long-term price outlook considerably. The lower-for-longer gas price is a reality in North America, and yet the outlook for demand growth remains relatively muted. Electrification has overridden gasification as the driving force in the energy transition, even as the price of gas has declined. The hope that the emergence of blue hydrogen as a storage and transport fuel will rescue gas demand is already wobbling due to a focus on green hydrogen.

The problem with being a transition fuel is that when events such as the COVID-19 pandemic dent demand growth, the length and breadth of the transition are shortened. This situation manifests itself in ways that are unique to the circumstances of particular regions across the world.

Low prices or not, long-term demand growth in North America and globally remains in question, and recent cancellations of pipeline infrastructure and LNG projects have increased downside risks. If the gas has nowhere to go, it won't be extracted, particularly now that flaring and venting are squarely in the crosshairs of those who would rather skip the gas part of the energy transition.

Finally, let's be clear that lower-for-longer gas prices do not imply that prices will stay as low as they are today. S&P Global Platts Analytics continues to project that gas producers will need to shift to more dry gas plays. This calls for a stronger price environment, with Henry Hub prices moving above a nominal $3.00 per one million British Thermal Units by the mid-2020s and remaining there through the end of the decade. This increase is not being driven by demand growth surpassing supply growth, it's just that the cost of producing dry gas is higher than the cost of producing associated gas tied to crude oil and NGLs.

Growth in gas demand will shift to China, India, and the Middle East over the next decade

Even if prices do rise slightly, the outlook for U.S. gas demand of -0.3% per year through 2023 would not change much. This is because it reflects the broader dynamics of how the energy transition will affect sectoral use. The healthy 2% annual increase in industrial gas demand in the U.S. will be driven by a significant competitive advantage over countries that produce or import gas at a higher cost. At the same time, gas use in the power generation (-1.7%) and residential and commercial (-1.3%) sectors will fall due to a combination of efficiency gains, weakness in top-line power demand, and fuel substitution tied to the decarbonization process.

Stronger growth in the transport sector will actually help Western Europe (0.3%) outperform the U.S. over the same period, but not by much. The real change for Europe will be on the supply side, with this likely to decline at an even faster rate than demand, requiring more imported volumes and exposing European prices to the global market to a greater extent. Europe's renewables build-out over the past decade has had the dual effect of accelerating the energy transition by marginalizing coal and lignite while increasing energy security by reducing the influence of global forces. Higher gas imports remain a concern in this regard, particularly if the share of a single supplier increases.

Asia and the Middle East will be the primary engines of demand growth, even if the costs of delivering LNG to the former are in sharp contrast to the low-cost consumption profile of the latter. More broadly, the LNG market is set to go through several more bullish and bearish periods due to the size of the liquefaction projects and the price incentives needed to bring them online. The next wave of LNG is already largely under construction, with nearly 180 million metric tons per year due to come online by 2026. COVID-19 has pushed this wave back by 12-24 months. Growth volumes are largely unchanged, although the providers of this growth are consolidating into fewer and fewer portfolios allied to international and state energy companies. Demand is growing largely in Asia, with China and India leading the future growth in LNG consumption. Overall gas use in China, India, and the Middle East will account for 61% of total gas demand growth over the next decade.

By sector, industry will drive higher gas demand, supplanting power generation

A decade ago, the power generation sector was the undefeated champion of gas demand growth, but this position has been severely undermined by investments in renewables and battery storage, as well as sluggish electricity load growth. Industrial gas demand growth has been revived by significant increases in elasticity supply, lower-for-longer prices, and an overall increase in the low-cost reserve base. Industrial gas demand now accounts for 58% of gas demand growth over the next decade; a decade ago, the power generation figure would have been over 60%. The Middle East, China, Southeast Asia, and the U.S. are the four largest growth regions for industrial gas use, while power generation use in the U.S., Europe, and Japan mark the biggest losses. Residential and commercial use in the U.S. is also slated to fall.

COVID-19 Exacerbates The Pressures On U.S. Natural Gas Producers

The aforementioned shortening and narrowing of natural gas' bridge role in the energy transition could have negative implications for our ratings on gas producers, particularly U.S. independent natural gas producers, over the next decade. We expect the pandemic to exacerbate preexisting challenges--including access to the liquidity and capital markets–-in addition to softening demand for domestic gas causing deferrals or cancellations of certain U.S. LNG export cargoes. In the longer term, a swifter transition to renewables would reduce domestic gas demand and could result in delays or cancellations in the construction of new LNG export facilities. This would exacerbate oversupply in the U.S., depress natural gas prices, and weaken the credit outlook and longer-term viability of the U.S. independent natural gas producers. Furthermore, as the energy transition progresses, access to the capital markets will likely become more limited for independent gas producers compared with larger and more diversified integrated companies.

Negative rating actions on U.S. independent natural gas producers were already underway at the start of 2020, driven by a deterioration in their credit metrics and liquidity and an increase in refinancing risk due to their limited access to the capital markets. Natural gas prices were under pressure due to the vast oversupply, and this has affected producers' profitability and credit metrics over the past year. Associated gas produced by oil-directed drilling operations, for example, in the Permian Basin, is growing at a rapid pace. This is an issue for gas-focused producers because such gas is divorced from the natural gas market's supply and demand fundamentals since these producers are primarily targeting oil production, not gas. Most of our natural gas producers remain on negative outlook.

We expect that the global energy transition that was underway prior to the COVID-19 pandemic will continue to present a significant challenge for U.S. majors ExxonMobil and Chevron, which have made less of a shift away from oil and gas to renewables than their European peers. This is partly the result of fewer government incentives to do so. However, we could see this change if Joe Biden is elected president in the U.S. presidential elections in November 2020. Mr. Biden has pledged $2 trillion to eliminate all GHGs from the electricity grid before 2035. While we have not seen an abrupt change of strategic direction by the U.S. majors as a result of the pandemic, it has the potential to shift future portfolio investments from oil and gas projects to renewables projects.

COVID-19 Further Reduces The Limited Appetite For New Long-Term Contracts That Protect U.S. LNG Debt Issuers

Currently, U.S. LNG issuers receive the majority of their cash flow regardless of the LNG spot price or whether a purchaser lifts LNG. Generally, offtake contracts are either tolling arrangements or sales-and-purchase agreements. Still, oversupply has reduced LNG purchasers' willingness to enter into new long-term contracts. A number of projects have received approval from the Federal Energy Regulatory Commission, but do not yet have final investment decisions because of a lack of off-take contracts, which are seen as necessary for a project to be financeable. However, growing interest from smaller emerging-market buyers could help mitigate supply pressure if these new customers continue using LNG once benchmark prices increase.

The U.S. power generation sector is set to shift focus from gas to renewables and downstream integration into retail

In the immediate wake of the COVID-19 pandemic in May 2020, the share of natural gas in the U.S. power generation sector reached a record high of nearly 40% of total generation in the U.S. However, 2020 may prove to be the high watermark for gas demand in this sector due to sluggish demand growth and robust renewable installations, which remove a key source of demand growth for natural gas producers. This will also prompt a shift away from gas-fired power, reversing the dominant trend for over ten years.

The pandemic has underscored changes in U.S. energy production and consumption patterns and facilitated shifts in unregulated utilities' strategies toward renewables and retail. Because of the low variable cost of renewables, we expect the U.S. to be long on energy in the shoulder months--when demand for heating and cooling is low--and short largely during the peaks of the summer and winter seasons. It may therefore become cheaper to buy power than produce it in the shoulder months, with physical assets needed largely to serve the summer and winter peaks. PSEG Inc.'s announcement of the divestment of PSEG Power was likely an acknowledgement of this impending disruption. The preponderance of PSEG Power's business was conventional wholesale power, which is seeing declining EBITDA.

We expect the North American regulated utility industry to continue to reduce its GHG emissions proactively, regardless of the near-term implications of COVID-19. The industry has been transforming itself for over a decade, primarily through coal-to-gas switching. Unlike ten years ago, the utility industry now emits less GHG than the transportation industry, reducing its reliance on coal-fired generation by about 50%.

European Gas Producers Are Focusing On Decarbonization, With Less Reliance On Gas, Or New Markets

Record-low spot gas prices, full storage, and declining volumes are putting pressure on gas producers' 2020 financial metrics. Notwithstanding such near-term financial pressure and a less supportive outlook for long-term global demand growth than we saw before the pandemic, we continue to view gas production as generally supportive for European oil and gas producers because it provides diversification, and in many cases, long-term contractual volumes.

While many European oil and gas producers once viewed gas as a key part of their long-term decarbonization strategies, they are now aiming increasingly at becoming diversified energy players through massive investments in renewables; carbon capture, utilization, and storage; and hydrogen. For example, BP's new strategy focuses on achieving zero net GHG emissions by 2050 or sooner by increasing investments in sustainable energy and energy partnerships, and by reducing hydrocarbon production by 40% through active portfolio management and no exploration in new countries.

By contrast, Russian and Middle Eastern gas producers, such as Gazprom, Qatar Petroleum, and Novatek, are focusing on monetizing their hydrocarbon reserves by targeting pockets of demand such as the growing Asia-Pacific markets or petrochemicals production. Gazprom is considering building a new pipeline capable of transporting 50 billion cubic meters (bcm) of gas per year to China, after commissioning the first stage of a 38 bcm capacity pipeline to China in December 2019. The Russian government's energy strategy aims to raise LNG exports to 108-189 bcm per year from 39.4 bcm in 2019 and increase local petrochemical production. Recent conflict around the completion and long-term role of the Nord Stream 2 gas pipeline in the European energy mix will not stop Russia from pursuing its stated role of maintaining a stable share of Europe's gas market while increasingly seeking diversification in China.

Gas will remain important in filling the gaps in Europe's generation mix left by the phase-out of coal and nuclear

The European Green Deal aims at zero net emissions of GHGs by 2050 and limits the long-term growth potential for gas in Europe. In addition, the European Green Taxonomy effectively excludes unabated gas, that is, fossil gas without carbon capture and storage. Still, we expect that even by 2030, gas will remain an important part of Europe's energy mix as growth in renewables and energy storage is unlikely to make up for the reduction in nuclear and coal generation. Investments in new gas-fired generation plants remain limited, as the load factors of the existing combined-cycle gas turbines are low in many markets, and most rated utilities are focusing their growth strategies on renewables or regulated electricity networks rather than gas-fired generation.

Regulated gas utilities in Western Europe face weaker growth prospects and a higher risk of stranded assets beyond 2030 compared to electricity. Regulatory pressures are already emerging in some countries, and have triggered outlook revisions for several European gas utilities in the U.K. and Spain. Regulated utilities in Western Europe are therefore looking increasingly for new growth aligned with the EU's focus on decarbonization, such as from renewable hydrogen. This strategy requires large investments, is subject to technological uncertainty, does not prevent stranded assets--for example, if the routes needed for delivering hydrogen and methane are different--and could heighten future business risk.

Chinese Gas Companies Should Benefit From Robust Growth In Gas Demand, With A Policy Focus On Indigenous Production

Chinese policymakers reacted to the COVID-19 pandemic by enacting measures to support the country's economy and increase energy security. On the one hand, this includes the relaxation of restrictions on building new coal-fired generation plants, which limit the growth prospects for gas, but on the other hand, there is a greater drive for domestic energy production, including natural gas. Chinese national oil companies are clear beneficiaries of this policy, and have already mapped out a seven-year (2019-2025) action plan to boost exploration and production and supply over 50% of China's gas.

The establishment of the China Oil & Gas Pipeline Network Corp. (PipeChina) earlier this year disrupts the national oil companies' integrated business model for natural gas. PipeChina aims to speed up pipeline investment and construction, which have been well behind schedule in recent years. However, it remains to be seen if PipeChina's huge capital expenditure will be compensated by the stable returns and cash flows that the 2016 regulation envisages.

City gas distributors are the beneficiaries of China's gas market liberalization and growing demand in the next five-to-10 years. Lower gas prices also help stabilize margins and support demand. Low transparency of regulations and political intervention remain the key regulatory risks for gas distributors, despite sector reforms moving in the right direction.

As for power generation, we still expect gas to be used for peak load, but it may lose ground to renewable energy in the longer term. Gas only accounted for 4.5% of China's generation fleet by capacity in 2019. On the flip side, rising LNG supply and falling gas turbine prices and low gas purchase costs may support moderate growth of gas for power generation in China.

The Energy Transition: COVID-19 Could Make 2020 Crucial For Renewables

In the U.S., the presidential elections in November 2020 could portend an increase in renewables growth in the next few years in case former Vice President Joe Biden wins, subject to Congressional support, as his plan includes $2 trillion in clean energy spending, while targeting a carbon-free power sector by 2035.

In Europe, COVID-19 has accelerated policy support, with one-third of the Recovery Fund allocated to green investments, combined with ambitious 2030 objectives for green hydrogen.

China's COVID-19-induced stimulus plans imply some headwinds for renewables because restrictions on new coal plants have been relaxed to support employment and the local economy. Moreover, the economy's trend to lower energy intensity has stalled (see "China's Energy Transition Stalls Post-COVID," published on Sept. 22, 2020). The country's next five-year plan (unveiled in March 2021) will reveal whether the country's energy policies this year are a blip, or signal something more permanent. The heightened focus on energy security could imply more support to abundant domestic coal, but we still would expect the government to support the continued of renewables in China's energy mix, especially now that China has recently committed to achieve carbon neutrality by 2060. A supportive factor is the strong 2021-2022 pipeline of now subsidy-free renewable projects.

Finally, India's renewables sector, a key growth market, has taken the biggest hit from COVID-19, due to reduced construction activity. Total renewables additions are down 40% so far in 2020 year on year. India's renewables industry, meanwhile, had already been facing more structural constraints, ranging from slowing growth in power demand, high counterparty risks, and transmission bottlenecks.

COVID-19 Generally Will Support The Market Share For Renewables

Despite delays to new-build activity tied to coronavirus pandemic-induced lockdowns, S&P Global Platts Analytics estimates that global renewables additions have been generally resilient so far this year and will be in the longer term. With more sizable downward revisions to fossil fuel demand, renewables are expected to have a larger market share compared to our pre-COVID outlook.

Solar PV capacity additions are expected to slightly decline year on year in 2020, but wind capacity additions could be up over 10%. The renewables industry continues to face some roadblocks to scaling up globally, but more constructive market and policy developments have been emerging in recent months that are signaling upsides to renewables investments in the years to come.

Even in the face of growing uncertainties about power demand recovery and prices, players continue to show robust commitments to invest in renewables across the globe as costs decline. Declining costs, combined with more renewables-friendly policies should offer support in a number of markets. The pipeline of renewables projects have remained generally stable over the past year, suggesting that COVID-19 will only marginally reduce the outlook for the industry.

Policy responses to COVID on renewables vary greatly across regions

China between green and black:   While domestic power demand has moved back above 2019's levels, China has announced a large number of solar PV and wind grid-parity projects in recent months. The country currently accounts for over one-third of annual global wind and solar additions, and these recent announcements suggest it will continue to be a key area for renewables investments, even as the country's coal newbuild policy has recently been relaxed and more coal plants are being brought online.

Europe's green mantra:   Policy support for clean energy and decarbonization is leading to significant upside to renewables additions in Europe. The European Commission's Hydrogen Strategy of July 10, 2020, clearly states that "the priority for the EU is to develop renewable hydrogen, produced using mainly wind and solar energy," which would require by 2030 "to scale up and directly connect 80-120 GW of solar and wind energy production capacity to the electrolysers to provide the necessary electricity." To put things in perspective, the EU-27 added in 2019 about 11 GW of wind, while added solar PV capacity was almost 14 GW in the same year. These policy ambitions have been announced as the power sector closes large amounts of conventional capacity, with S&P Global Platts Analytics projecting almost 45 GW of coal/lignite capacity and 18 GW of nuclear coming offline within the next five years across Western Europe.

U.S. green strategy on balance:   On the other side of the Atlantic, the U.S. has not provided any support for green initiatives in stimulus measures to date. State mandates, tax incentives, and ESG corporate initiatives continue to be key drivers of U.S. installations so far, but the outcome of the November elections will be clearly an important driver of further development. While the Trump administration has not signaled an intention to support of green power initiatives, the Biden platform has promised $2 trillion in clean energy spending in its first term, while targeting a carbon-free power sector by 2035. These measures will, however, require congressional legislative approval.

A larger market share for renewables comes with bottlenecks

Curtailments: The increasing role of renewables during hours of lower power demand further underscores the risks of curtailments.   The increasing role of renewables in the power mix further underscores the risks of curtailments. At the same time, as more conventional generating capacity is retired, especially in the U.S. and Europe, more batteries will be needed to boost flexibility needs and supplement renewables for peaking capacity.

While California-ISO faced severe power shortages this summer during an intense heat wave, with a combination of high demand, limited import availability, low wind output, and unplanned outages, leading to rolling blackouts, it's interesting that an expansion of the Moss Landing battery energy storage system has been recently approved, which would make it the largest battery project currently in development globally. The project would include up to 4 x 300 MW/1200 MWh systems to be constructed over a five-year period. Combined with the 300 MW already under construction at the site, the project would boost capacity and energy storage to 1,500 MW and 6,000 MWh, respectively. While it's not clear if this project will be fully built, storage will play a major role in replacing retiring gas and nuclear units in California. As more conventional generating capacity is retired, especially in the U.S. and Europe, more batteries will be needed to boost flexibility and supplement renewables for peaking capacity.

Global emergence of offshore wind:   While solar PV will remain the major technology in annual additions, S&P Global Platts Analytics expects a growing role for offshore wind facilities, especially in Europe, where they will account for almost 40% of total wind additions by 2025 versus only 22% in 2019. China's offshore wind capacity is trending higher, as we expect 4 GW commissioned every year, and while offshore development is in much earlier stages in the U.S. and is starting to ramp up. Offshore wind is emerging as a more viable option also in northeast Asia.

U.S.: COVID-19 Had Little Impact On Renewables Growth, But November Elections Might

An acceleration of the renewables market may depend on presidential elections, as a Biden win could spark the next boost:   State mandates, tax incentives, and corporate initiatives continue to be key drivers of U.S. installations so far. With a phaseout for wind credits in 2021 and step-downs for solar Investment Tax Credits (ITC), we do expect a decline in installations. However, a Biden win along with a democratic sweep in Congress (the House and Senate) could accelerate renewables policies and uptake demand in the U.S. Nevertheless, with a phaseout for wind credits in 2021 and step-downs for the solar ITC, we do expect a decline in installations. By contrast, the Trump administration has not signaled any support for green power initiatives.

Renewable tax credits outweigh COVID impacts.   Renewables installations in the U.S. have historically been very shaped by federal tax credit policy, COVID-19 notwithstanding. The sharp increase in renewables in 2020--especially wind installations-- is unsurprising as the Production Tax Credit (PTC) incentive (and ITC in lieu of the PTC) has increased from 40% to 60% of the full credit amount (and from a 12% ITC to 18%) for qualified wind projects commencing construction in 2020 rather than 2019. This "step up" in tax credit eligibility created a market dynamic pushing for higher installation in 2020. The importance of timing highlighted concerns that COVID-19 risks to supply chains could delay the delivery of the renewable pipeline. Work stoppages have most affected the relatively smaller distributed solar segment, which includes residential and commercial installations. To be sure, we expect the U.S. distributed generation segment will experience a 30% decline in 2020 compared with 2019. While that's not the case for utility-scale solar, the pandemic has tempered growth projections and has created uncertainty for projects under development.

However, new guidelines in the wake of COVID-19 have assuaged concerns. They allow onshore wind projects that began construction in 2016 and 2017 to have an additional year (five years instead of four) to finish construction and still receive PTC benefits. Similarly, solar developers will be allowed to retain ITC eligibility on equipment bought in 2019 to be delivered into October 2020.

Renewables continue to grow, supported also by ESG and declining costs.   Despite COVID-19, we expect wind installations to nearly double in 2020 to nearly 19 GW from just over 9 GW in 2019 (total installed capacity being 105 GW). We expect residential solar installations to slow some, but still expect utility-scale solar at the same pace as 2019 to add 12 GW (from a 90 GW base). The proportion of energy produced by renewables as a whole had increased to nearly 16% in terms of terawatts (or 25% when including hydro generation). ESG and sustainability initiatives are giving renewables an extra push. In addition, with overnight capital costs projected to decline to $1,050/KW and $825/KW in 2025 from $1,250/KW and $1,150/KW in 2020 for wind and solar, respectively, we expect renewables deployment to continue to accelerate in the medium term. Even as natural gas-fired generation spikes in 2020, the fuel itself is unlikely to challenge renewables growth. We do not see a case to justify longer-term gas-fired power sector investment and think the very strong jump seen in 2020 will represent peak natural gas-fired electric generation as a share of total power generation.

Lower returns and more risks lie ahead.   While renewable growth has been strong, returns on the investments have not been as impressive over the past two to three years--as developers are focusing on obtaining scale. At the same time, according to S&P Global Market Intelligence data, roughly 50% of U.S. wind PPAs set to start in 2020 have terms of 15 years or shorter, whereas that proportion was less than a quarter on average in the past decade. A similar trend toward shorter PPAs has also emerged for solar PV. Given the importance of tax credits, financing also typically consists of tax equity in the capital structure. A combination of aggressive resource availability and merchant price assumptions has resulted in single-digit returns for developers in the PPA period, leaving significant market risks during the merchant tails.

We also expect lenders to be more selective.   As global financial markets struggle to cope with COVID-19, financing, in general, has become more risk averse. As such, traditional debt lenders may view a renewable energy project in 2020 as riskier than other financing opportunities. This will likely make debt financing more expensive in the near term and restrict the availability of finance for new market entrants. The risk of supply and construction delays has also slowed tax equity, and financing generally, for projects other than those already in the pipeline or new projects from tried and tested developers and sponsors. Thus, for projects expected to enter the finance market in the coming months, the outlook remains somewhat uncertain.

Europe: Economic Recovery Plans Call For An Acceleration Of Renewables

Policy support for clean energy and decarbonization is leading to significant upside to renewables additions in Europe.   The latest major step in Europe toward an energy transition dates from just before the pandemic, with the European Green Deal of December 2019 setting out a growth strategy for a more sustainable economy targeting carbon neutrality by 2050. This would notably stem from a gradual exit from coal, oil, and natural gas; a significant increase in renewables; but also from a comprehensive restructuring of sectors like construction, transport, and agriculture. It implied more of a redirecting of funds, as new monies into renewables were limited to €7.5 billion. The COVID-19 policy response has added teeth to the transition, as it contemplates €225 billion for green investments out of the total €750 billion recovery fund, called the Next Generation Plan. This will prove positive for European utilities, although we recognize implementation of support mechanisms will take time to materialize.

Hydrogen as a potential future booster:   COVID-19 political responses also focus on energy independence. Several multibillion budget allocations to develop a European green hydrogen industry since the beginning of the year (with hydrogen produced with renewable power) will further promote the growth of renewables over the coming decade. As a storage solution, hydrogen could notably help address challenges from renewables' intermittency and seasonality (complementing batteries) and increase demand for decarbonized energy from sectors such as heavy vehicle transport and heavy industries.

Investment plans in renewables are growing larger, but risk-adjusted returns are shrinking, driven by investor appetite, green financing and persistent low cost of capital.   Almost all European utilities aim to boost their investments in renewables, while European oil and gas majors are embracing the energy transition and increasing their renewables ambitions. In addition, the draft European taxonomy will offer incentives to European institutional investors and banks to support green and sustainable investments. The only negative development may come from households, which may delay or cancel their plans to build rooftop solar PVs. At the same time, the low cost of capital (a key part of overall costs) continues to support the competitive position of renewables: remuneration sank to a record low of €11/Mh at the latest Portuguese auctions. The resulting effect of increased competition and expectations of lower costs is a likely squeeze in returns, which may affect future performance for renewables investors.

Permitting hurdles, system costs, and subsidy-affordability may slow down the pace.   Permitting remains a major bottleneck for the development of renewables in Europe now: Local opposition, which stands in contrast with Europe's ambitions, consists mainly of "not in my backyard" concerns in generally dense territories. The Green Deal also intends to address this by simplifying and shortening permitting processes, while repowering opportunities on existing sites may also offer historical players further growth opportunities. Yet, this is still to be designed and implemented. Similarly, transmission and interconnection projects face concerns about permitting and system costs. Massive investment in such projects is needed in order to transport power from windy onshore and offshore areas to remote to high consumption areas, as well as to cope and manage the higher penetration of renewables (as interconnectivity materially reduces intermittency risks). Last but not least, COVID-19 may add to concerns about the already high cost burden stemming from various subsidy schemes for renewables. Tariff deficits could become more to the front, as weaker economic demand for power and lower prices confront growing renewables output.

Merchant risk remains a hurdle, as the PPA market is not taking off rapidly.   The market expects PPA to replace fading subsidy schemes, provide long-term earnings visibility and support project financing. Yet, the lack of contractual standards and diverse legal systems have so far limited PPAs' growth potential in Europe. In addition, the economic uncertainty induced by COVID-19 may further limit players' willingness to lock in long-term prices or take on long-term counterparty risk. Existing fixed-price auctions provide the long-term visibility needed to keep capital costs low. Acting as floating to fixed swaps, auction prices do not necessarily imply "subsidized" tariffs, as competitive forces have driven prices down. Moreover, we believe that merchant risk remains hard to assess, even more in the current power and carbon price environment. In our view, renewable projects exposed to such risks are only financeable if backed by either by PPAs or minimum floor price protection. In an environment of less subsidized or fixed prices, we believe large, solid, and established players will be the main beneficiaries, as they enjoy in-house (integrated) supply and trading activities as well as vertical integration. It may help them consolidate their respective market positions. Doing so is, however, not just the space of utilities, as Europe's oil and gas majors are making inroads too (see "Write-Downs, While Eye-Catching, Are Not The Largest Issue Facing Oil And Gas Supermajors," published on RatingsDirect on Aug. 3, 2020).

China: COVID-19 Is Not Stopping Renewables Growth, But More Support For Coal And Stimulus For Heavy Industry Could Stall The Pace Of China's Energy Transition

We continue to see China as a key growth area for renewables investments, bolstered by its just announced commitment to achieve carbon neutrality by 2060, even as coal new-build policies have recently been relaxed.  As a result of COVID-19, more coal power projects were approved in the first half by local governments to stabilize demand and employment. Increased support for abundant domestic coal (also in view of less predictable geopolitics) and rising industrial energy use amid the COVID-19 stimulus for infrastructure and heavy sectors could bring China's declining energy intensity into reverse (see "China's Energy Transition Stalls Post-COVID," published on RatingsDirect on Sept. 22, 2020). We will only learn whether China is executing an energy U-turn after the next five-year plan for 2021-2025 is published in March next year. Still, we still would expect the government to remain steadfast in its support of the rise of renewables in China's energy mix, as evidenced by President Xi's recently statement that China intends to to become carbon neutral by 2060.

Renewables' project pipeline remains supportive, despite the end to subsidies.   Despite COVID-19 causing some project delays and fewer capacity additions in the first half of 2020, we believe the rush for commissioning subsidized capacity in the run-up to grid parity is the main driver of China's renewable energy growth in 2020. A successful transition to subsidy-free projects assumes that technology-induced costs decline further, allowing renewable energy to compete at on-grid tariffs (that is, the reference coal power prices). Still, renewable projects will continue to be granted for other preferences, such as prioritized access to grids and enhanced transmission capacities for renewables. A positive signal has been the announcement of a growing number of solar PV and wind grid-parity projects in recent months, supporting capacity growth in 2021 and 2022. Up to August 2020, 15.9GW in wind and 47.8GW in solar power capacity has been approved for the grid-parity pilot program and required to be commissioned by the end of 2021 (for solar) and 2022 (for wind), although execution wobbles cannot be ruled out.

Increasing state-owned entrants are changing the landscape of China's renewable energy sector.   Under both the economic and political push for energy transition, state-owned conventional energy companies are actively growing their clean energy portfolio. By leveraging their advantages in funding, resources, and technology, they are adding new capacity in wind and solar power aggressively through both new builds and acquisitions. They are also the key developers of offshore wind, and the winners when grid parity and merchant projects are coming on stream.

Key challenges include climbing costs, and competition from coal and curtailments.   Unchanged deadlines set for subsidized projects commissioning this year are posing headaches for the developers, given supply chain disruptions and construction delays due to the COVID-19 outbreak. The rise in construction costs caused by strong demand may undermine project returns and potentially delay the commission of some grid-parity projects. Moreover, the enhanced competitiveness of coal power due to declining fuel prices and intensifying market competition may reduce the returns of grid-parity projects or delay them. Finally, intermittent and outsized supply of renewable energy threatens the stability of grid networks and worsens possible curtailments. Some provinces start to require battery storage in place to meet up to 15%-20% of the capacity of new wind power projects. China's energy regulators are also seeking comment on bundling the energy storage system with all of the wind, solar and coal power (or hydropower) projects in progress. This may also help reduce the need for building excessive coal power as peaking capacity. In our view, the key to success may include sorting out a low-cost and viable business model for the battery storage solution.

Delayed subsidy payments, evolving policy risks, and the lack of a PPA market weigh on funding.   Prolonged subsidy payment delays have eroded cash flow and returns and heightened liquidity risk, especially for private developers with little access to funding. By the end of 2019, only 56% of wind power and 23% of solar power PPA awarded received subsidy premiums, and national subsidy deficits keep widening. New policies issued in early 2020 allow some projects commissioned after March 2016 to apply for subsidies, subject to a stringent verification process. However, without significant increases in budget sources, more projects qualifying for subsidies may dilute the payments to earlier projects currently receiving them. Recently, the industry association proposed state-owned grid companies to issue government-backed bonds to settle the arrears of receivables, but there is no official statement on the likelihood and progress of such a proposal. While earlier projects have been able to securitize subsidy receivables, the policy and cash flow uncertainty and lack of a PPA market have meant that project finance or securitization are not options for more recent projects. Financial lease and bank loans are two major funding channels for renewable projects in China. Banks usually provide loans pledged with power generation revenue after commissioning. More costly, financial leases can bridge funding needs at least at the construction stage.

India's Renewables Additions Take The Biggest Hit From Lockdowns

COVID-19 is having the biggest impact on renewables new builds in India, with total renewables additions of only 4.3 GW in 2020 at the end of August, a decline of almost 40% year over year.   Solar PV capacity reached over 35.3 GW at end-August and is moving closer to wind capacity, which stands at 37.9 GW. However, India's solar PV development has been facing several logistical challenges, with imports of solar panels from China disrupted earlier this year, while labor shortages due to lockdowns slowed construction activity in the second and third quarters. In addition, a lack of clarity about the extension of customs duties on imported solar PV cells and modules has also been cited as a cause of delays. India's wind deployment is also decelerating, with only 0.7 GW of wind connected to the grid so far in 2020, compared with 2.4 GW in 2019.

A robust pipeline of projects with PPAs competitive against fossil fuel and power grid costs.   The slowdown in installations is occurring as the pipeline of projects backed by PPAs remains large. Since the pandemic has been undermining construction activity, deadline extensions have been granted. Also, the pipeline of utility-scale solar PV projects in development stands at over 42 GW, while solar PV projects for a total of 17 GW have been awarded in auctions held in the first half of 2020, up 7 GW year on year. Remuneration in recent solar PV auctions has ranged between Indian rupees 2.3- 2.9/kWh ($33-$41/MWh). This price is well below the current prevailing PPAs covering coal and gas plants and below the benchmark grid costs for power, APPC, as determined by the Central Electricity Regulatory Commission.

Structural factors have also been constraining India's renewables scaling.   COVID-19 has unfolded as the renewables industry in India was facing more structural constraints in the process of scaling. Power demand growth has already slowed in the second half of 2019 and, despite a recent recovery for grid-connected loads in the third quarter, power demand remains below historical trends. A more uncertain power demand outlook could further undermine distribution companies and off-takers' appetite to lock into long-term PPAs, while counterparty risks and receivable delays remain a concern for renewable developers. While a growing number of hybrid projects combining solar PV with wind and batteries are being developed, land scarcity and grid bottlenecks could represent a drag on future investments.

S&P Global Platts Analytics assumes solar PV additions will rebound over the remainder of the year. We assume total renewables for the 2020-2025 period will increase an average 14 GW/year, down 14% from our pre-COVID-19 view. Despite great solar and wind potential, India's renewables industry will require further strong policy action to overcome the current difficulties.

Related Research

S&P Global Ratings

• Write-Downs, While Eye-Catching, Are Not The Largest Issue Facing Oil And Gas Supermajors, Aug. 3, 2020
• Germany's Green Levy Deficit Will Not Limit Transmission System Operators' Debt Capacity, July 29, 2020
• WEBCAST/SLIDES: Power Markets Outlook And Credit Implications In The Age Of COVID-19, July 10, 2020
• COVID-19: What Would A New Tariff Deficit Mean For Spain's Electricity System Operators? June 25, 2020
• Credit FAQ: Energy Transition: The Outlook For Power Markets In The Age Of COVID-19, June 25, 2020
• The Energy Transition And What It Means For European Power Prices And Producers: Midyear 2020 Update, June 8, 2020
• The EU's Drive For Carbon Neutrality By 2050 Is Undeterred By COVID-19, April 29, 2020

S&P Global Platts Analytics

Emissions

• EU Signals Interest in Deeper GHG Targets, Stronger Policies in Transport Sector May be Necessary, Sept. 17, 2020
• Absent Action at IMO, EU ETS Coverage of Shipping CO2 on the Horizon? Sept. 16, 2020
• Leaked EC document offers very ambitious vision of European hydrogen markets by 2030, June 26, 2020
• Denmark codifies ambitious 2030 emissions reduction targets, June 24, 2020
• Quantifying Risk: How much COVID-19 could change consumer behaviors and impact long-term oil demand, March 24, 2020

Oil

• Upstream oil investment and the energy transition, July 13, 2020
• Investment requirements in a 2DegC world, June 3, 2020
• Could oil demand peak by 2025 in a post-COVID-19 world? May 5, 2020
• Quantifying Risk: How much COVID-19 could change consumer behaviors and impact long-term oil demand, March 24, 2020

Gas

• Global Power Forecast – Risks and Opportunities, Aug. 12, 2020
• European Gas Five-Year Forecast, July 20, 2020
• North American Gas Five-Year Forecast, June 24, 2020
• First Look at COVID-19 Impacts on Long-Term Global Gas Balances, June 10, 2020

Renewables

• European Electricity Five-Year Forecast, Sept. 10, 2020
• Webinar Replay & Slides: North America Power Markets Long-Term Forecast, Sept. 2, 2020
• Global Wind Market Outlook (2020-2025), Aug. 24, 2020
• World's largest battery installation permitted in California; economics of build still questionable, Aug. 18, 2020
• Global Renewables Outlook (2020-2025), May 19, 2020

Policy

• Long-term forecasts of North America's power markets and their role in energy transition, Sept. 2, 2020
• US House Democrats' infrastructure plan unlikely to pass, but signals party priorities for economic recovery, June 24, 2020
• US election and climate policy: Biden platform points to carbon price with broad coverage, May 26, 2020
• US CO2 Monitor, May 1, 2020

S&P Global Ratings:	Karl Nietvelt, Paris (33) 1-4420-6751; karl.nietvelt@spglobal.com
	Massimo Schiavo, Paris + 33 14 420 6718; Massimo.Schiavo@spglobal.com
S&P Global Platts Analytics:	Roman Kramarchuk, New York +1 (212) 438 9146; roman.kramarchuk@spglobal.com
	Dan Klein, New York (212) 438-9144; dan.klein@spglobal.com