In 2016, BCG predicted that the liquefied natural gas industry was entering a challenging period. The reason: a growing imbalance between supply and demand. (See The Evolving LNG Market: A Challenging Supply-Demand Outlook for LNG Producers, BCG Focus, November 2016.)
One year later, developments in the LNG market have borne out that prediction. 1
Based on BCG’s proprietary LNG market model.
LNG demand finally began growing again in 2016, after four years of stagnant consumption stemming from high market prices (from 2011 to the end of 2013) and a challenging supply environment. However, a significant amount of LNG supply—more than 50 billion cubic meters per annum (bcma)—came online during 2016. This supply growth is outstripping demand requirements, preventing a rebound in LNG prices (which began to decline in 2014) and squeezing industry margins. This margin squeeze from excess supply, which is likely to persist until at least 2020, is further amplified by excess supply in the LNG vessel market. While LNG suppliers may be locked into long-term shipping contracts, LNG buyers are asking for contracts that reflect the lower spot charter rates.
Meanwhile, new sources of demand growth are creating additional challenges. Beyond China and India, where consumption increased by roughly 20% in 2016, significant demand growth is coming from so-called niche markets, such as Egypt and Pakistan. Contracts in these markets are typically higher risk and for lower volumes and shorter periods than contracts in more established markets. As a result, it is difficult to leverage the demand from niche markets to finance new liquefaction projects.
In response to these shifting market dynamics, suppliers must take action in three areas. First, they must focus increasingly on managing costs, developing only those projects that are competitive under current pricing and implementing structural cost-saving measures, such as standardized, modular approaches to plant construction. Second, they must develop sophisticated sales and trading strategies to address the needs of emerging buyers and improve their risk management processes as smaller, higher-risk contracts become more prevalent. Third, they need to consider selective downstream investments that could support the development of new markets. Such moves will allow them to lock in demand and achieve higher LNG prices by means of vertical integration.
Natural gas remains a triple-A+ resource, one that is not only abundant, available, and affordable but also acceptable from an environmental point of view. The supply of natural gas has grown significantly, fueled in large part by the shale gas revolution in the US. At the same time, more and more countries are finding reserves within their borders. Natural gas is cheaper on a levelized basis than many renewables and not significantly more expensive than coal. And its low level of greenhouse gas emissions relative to coal (an efficient natural gas industrial boiler emits roughly 40% less carbon dioxide than a coal industrial boiler) has further enhanced the attractiveness of natural gas in countries aiming to control such emissions. (See “Will Natural Gas Demand Soar as Emissions Reduction Intensifies?” BCG article, May 2016.)
We therefore expect a healthy 1.5% compound annual growth rate in natural gas demand between 2015 and 2025. Even under a scenario of challenging conditions for growth—with renewables taking off extremely rapidly in the years ahead, for example—natural gas demand will continue to expand at an annual rate of at least 0.5%.
Within the natural gas market, LNG demand growth has been particularly robust. From 1990 through 2016, LNG demand grew at an annualized rate of 6%, compared with 2.3% for natural gas. However, there are significant changes in store for the LNG market, driven by the expected short-term supply-demand imbalance and the increased importance of niche markets.
The LNG market, which now stands at about 350 bcma, or roughly 10% of the total natural gas market, will face significant challenges owing to oversupply for the next three to five years. To understand why, it is important to assess the trajectory of both demand and supply.
LNG Demand—a Return to Growth. LNG demand growth has been a bit of a roller coaster. From 1990 to 2011, demand soared from about 72 bcm to 327 bcm—an 8% annual growth rate. Then, from 2011 to 2015, consumption was flat, owing to high LNG prices during much of that period and limited supply. As noted earlier, growth picked up again in 2016, thanks to demand from markets like China and India as well as from new niche markets. We expect demand to continue this upward trajectory, increasing 5.3% per year under our base scenario, from 332 bcm in 2015 to 559 bcm in 2025.
As noted in last year’s report, our demand projections are subject to significant uncertainties stemming from four factors. First, a country’s demand for energy is heavily dependent on its economic growth—something that cannot be predicted with precision. Second, a country’s energy policies can shift over time. For example, the amount of nuclear capacity restored in Japan or the limits on coal use imposed in China could have a significant impact on our estimates. Third, the competitiveness of LNG compared with that of alternative fuels is hardly static. In Europe, for example, changes in coal and carbon dioxide prices will determine the competitiveness of gas in the power industry, and thus the LNG volumes that power plants will ultimately consume. Finally, the development of alternative sources of natural gas is difficult to predict—a larger than expected increase of either domestic gas production or pipeline imports in China, for example, would reduce LNG demand in that country.
Due to these uncertainties, the difference between our high- and low-demand scenarios is quite wide. (See Exhibit 1.)
In fact, changing expectations stemming from some of the factors that drive LNG demand have led to some revisions in our forecast since last year:
Rapidly Expanding Supply. The current LNG market is marked by the largest supply increase in its history. Fourteen projects are expected to become operational between 2016 and 2020.2 Notes: 2 The projects are AP LNG T1/T2, S. Pass T1-T5, Gorgon LNG, MLNG Train 9, Kanowit, Wheatstone, Ichthys, Prelude FLNG, Yamal, Freeport T1-T3, Cameron T1-T3, Cove Point, Corpus Christi LNG T1/T2, and Tangguh T3. These projects have a combined capacity of roughly 200 bcma—about 45% of global supply in 2015.
Additional projects representing a total of about 270 bcma have been proposed but have yet to secure a final investment decision (FID). However, as we noted last year, most of these projects are unlikely to materialize given persistently low LNG prices. Only one brownfield project, Tangguh Train 5 in Indonesia, secured an FID in 2016.
However, there are producers able to secure an FID even in this low price environment. The new LNG project announced by Qatar is likely to move ahead given the low cost of production in that country. Ultimately, the number of projects currently without FIDs that actually come to fruition will depend on the industry’s adoption of measures that lower project costs.
We have developed three scenarios for supply growth between now and 2025 given various assumptions about the progress of these projects:
The Bottom Line Outlook. Strong supply growth will result in oversupply in 2019 under seven of nine of our projected supply and demand scenarios. (See Exhibit 2.) Oversupply will contribute to increasing liquidity in the LNG market. Spot and short-term volumes of LNG have been rising steadily and significantly, climbing from 25 bcm in 2005 to about 100 bcm in 2015. This growth is expected to continue, with volume in 2025 exceeding 200 bcm.
This rising liquidity is bad news for LNG marketing margins. Highly liquid markets, including the US and the Northwest European natural gas markets, have historically had very low marketing margins. The LNG market, however, has long boasted high marketing margins—but as liquidity increases, those margins will contract.
At the same time, the LNG market’s oversupply will ensure continued low LNG spot prices over the next several years. But three factors will support a floor under those prices:
Until recently, historically large and developed markets, including Europe, Japan, and South Korea, accounted for the bulk of LNG demand and growth. These markets have low credit risk and typically can be served through traditional long-term contracts involving volumes of more than 1 bcma.
During the past decade, however, new markets have become a major driver of demand. The number of countries importing LNG grew from 9 in 1990 to 31 in 2015. In particular, five nascent markets—Egypt, Pakistan, Jordan, Lithuania, and Poland—grew substantially from 2014 through 2016. New demand from these countries reached nearly 19 bcma in 2016, equivalent to the total combined demand of Spain and Italy.
This trend is expected to continue, with a number of other countries potentially beginning to import LNG by 2025. Among the possible new markets: Bangladesh, the Philippines, Malaysia, Indonesia, Bahrain, Panama, Uruguay, Colombia, the Caribbean region, Morocco, and South Africa.
The issue for LNG suppliers is that the contracts with buyers in these markets, which typically have lower credit ratings than buyers in more developed markets, look quite different from traditional agreements. They involve lower volumes, greater flexibility in the ultimate volume purchased, and shorter time frames. Contracts signed during the past few years have already changed significantly because of the requirements of these new customers. (See Exhibit 3.)
The net impact of these smaller, shorter-term, higher-risk contracts is to squeeze supplier margins. This is further exacerbated by the surge in capacity in the LNG vessel market. (See the sidebar, “Impact of Oversupply in the Vessel Market.”)
LNG tanker fleet capacity increased 24% from 2011 to 2015—from 51.9 million cubic meters to 64.4 million cubic meters—new construction sparked in part by the spike in LNG demand that followed the Fukushima disaster. Many of these vessels were not tied to long-term contracts but rather were ordered mainly to capture cross-basin price differentials in LNG vessel shipping rates.
However, LNG demand has remained relatively constant, and the need for new vessels in certain locations has been reduced as the price differential across basins collapsed. As a consequence, LNG charter rates have fallen dramatically since the beginning of 2014, to $20,000–$25,000 per day for steam vessels and $30,000–$35,000 per day for dual-fuel diesel electric and tri-fuel diesel electric vessels. Those rates are well below the charter rates that buyers under long-term contracts must pay. (See exhibit below.)
This pressure on prices is unlikely to abate anytime soon. There are orders on the books for significant numbers of additional LNG vessels, construction that we predict will push total capacity to 80 million cubic meters at the end of 2020.
This surge in capacity will have two major repercussions. First, there will be pressure to retire older vessels with higher operating costs. The new vessels tend to have 40% to 50% lower energy consumption per transported cubic meter. And they are faster, reducing shipping time by roughly 5% on longer routes. Second, LNG producers will face further margin pressure as buyers demand LNG contracts that reflect the lower spot prices for vessels, while suppliers are still locked into older, higher-cost vessel contracts.
The shifts in the LNG market—particularly oversupply and the development of new, higher-risk markets—require new thinking. LNG players should take action in three areas.
The degree to which LNG suppliers are embracing these strategies varies. It will be critical for them to assess which can help them thrive in a difficult environment.
LNG suppliers should be prepared for a bearish market over the next several years. We expect substantial oversupply, driven by the 190 bcma of additional capacity projected to come online in the next three to five years. That oversupply will keep LNG spot prices at low levels and put pressure on industry margins, while increased liquidity in the market will squeeze marketing margins.
In this challenging environment, the industry will need to assume bigger risks, with shorter and smaller contracts with buyers in niche markets. Suppliers will need to up their game in risk management while also moving aggressively to reduce development costs for new projects in order to ensure that they are economically viable.
This is the second in a series of annual reports on the evolving LNG market. Each report analyzes the supply-demand environment using BCG’s proprietary LNG market model and discusses issues relevant to the industry.