Lower global energy demand due to the COVID-19 pandemic threatens the future of gas more than other fuels over the next 20 years. Gas will be to some extent squeezed out by lingering coal supply and growing renewables.
Still, we do not expect gas demand to peak over the next 10-20 years globally, owing to industrial demand rather than power generation. China, India, and the Middle East will account for 61% of growth over the next decade.
Gas demand growth has probably peaked in the U.S. power generation sector, as utilities' strategies shift to renewables and retail integration.
Smaller U.S. independent gas producers face the greatest credit impact, as the pandemic exacerbates preexisting pressure on their profitability, credit metrics, liquidity, and refinancing ability. In Europe, the Green Deal is unlikely to support gas in the long term, even if gas remains an important part of the energy mix owing to the phase-out of coal and nuclear power. Uncertainty about the future role of gas is beginning to weigh on gas utilities' regulatory returns.
Large gas producers in Europe are focusing increasingly on decarbonization and green energy, or diversifying into growing markets in Asia.
This is a market view from Ira Joseph, Head of Global Gas and Power, S&P Global Platts Analytics. S&P Global Platts is a division of S&P Global, as is S&P Global Ratings. Therefore, what follows are the sole views of S&P Global Platts, subject to its citation policy, available upon request.
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.
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.
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.
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.
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.
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.
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.
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%.
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 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.
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 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.
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