by Vaclav Smil
So what is next? Continuing demand for LNG in Asia in general, and in East Asia in particular, is easy to predict. Natural gas is still only 10% of the continent’s primary energy supply (only about 40% of the global mean) as established importers (Japan, South Korea, Taiwan) are being joined by China (first imports in 2006 to Guangdong), India (planning at least 10 new LNG terminals), Vietnam, and the Philippines. China has still a long way to go before surpassing Japan as the world’s largest LNG importer (it bought about 25 Gm3 in 2013 compared to Japan’s 113 Gm3), but the coming demand is huge, expected to rise to 315 Gm3 in 2019, an increase of 90% above the 2013 volume, in order to displace more coal in household heating and city-based electricity generation and hence reduce excessive levels of urban air pollution.
As a result, Asian LNG imports could easily rise by 50% between 2010 and 2020—but the actual aggregate demand will depend on the eventual course of Japan’s energy policy (how many nuclear stations will be eventually restarted?), South Korea’s economic growth and expansion of nuclear capacities, and China’s success in boosting domestic production and the country’s extent of additional imports from Central Asia and Russia. The greatest import potential elsewhere in Asia is obviously in India, and its volume will be determined by the success of the new BJP government installed in 2014. Technical advances will result in a growing number of floating LNG plants designed to harness stranded gas (Figure 8.5). Self-propelled offshore liquefied natural gas production vessels can do it all: pretreat the gas, liquefy it, store it onboard, and off-load it to LNG tankers (Peck and van der Velde, 2013). Vessels by Flex LNG have annual production capacity of 1.7 Mt, while other developers are planning ships with capacities of 1.6–2.5 Mt. Floating regasification with permanently moored vessels, either offshore or in a port and ship-to-ship transfer of LNG, will also become more common.
Figure 8.5 Floating LNG plant.
Reproduced with permission from Photographic Services, Shell International Limited.
As for individual LNG exporters, fairly predictable trends include both expected shifts and surprising changes. Continuing development of huge offshore natural gas reserves in the Indian Ocean off Western Australia—now mainly by two projects, Pluto by Australia’s Woodside costing about $11 billion and Gorgon, a joint venture by Chevron, Exxon, and Shell, costing more than $40 billion—should make the country, now the world’s fifth largest LNG exporter and major supplier of East Asia, second only to Qatar by 2020. In contrast, LNG imports by hydrocarbon-rich countries represent a shift that was unexpected even 5 years ago. In 2009, Kuwait was the first Gulf country to import LNG for an offshore storage to cover its summertime peak demand; it was followed by Dubai in 2010 (also for an offshore storage, in addition to pipeline imports from Qatar) and (as already noted) by Malaysia in 2013.
Dubai’s profligacy is particularly astonishing. As if the world’s tallest building (Burj Khalīfa) and the giant Dubai Mall shopping center were not enough, Dubai Holding (owned by the state’s ruler Sheikh Mohammed bin Rashid Al Maktoum) announced in July 2014 that it is planning to build the Mall of the World, a temperature-controlled city under a giant glass dome with the world’s largest mall and an indoor park, hotels, health resorts, and theaters that would occupy 4.45 Mm2 and include 7 km long promenades (Dubai Holding, 2014). The proponents hope to provide “pleasant temperature-controlled environments during the summer months,” making it “an attractive destination all year long” for anticipated more than 180 million annual visitors. In aggregate, Middle East’s growing dependence on natural gas means that by 2025 the region’s LNG import needs may approach 15 Mt/year, divided among Kuwait, UAE, and Saudi Arabia (Fesharaki, 2013).
Qatar’s role in all of this is as crucial as it is uncertain. Politically, it is a curious amalgam: a supporter of Egypt’s Islamist Muslim Brotherhood that has financed not only Al Jazeera but also jihadist groups in Syria’s civil war and maintains links with the Taliban while hosting a large US air base at Doha. How long lasting will be this peculiar arrangement in the region that has already seen too many political upheavals? Moreover, the world’s largest exporter of LNG has also seen its domestic natural gas consumption rising rapidly: it had nearly tripled between 2003 and 2012 (with most of the gas going for electricity generation and water desalinization), but the overall gas extraction had more than quadrupled. There is no imminent supply problem, but in 2005, the government decided to place moratorium on further development of the North Dome until 2014.
If Qatari shipments level off, how much can be supplied by North America’s shale gas expansion? Canada’s only LNG facility is Canaport, a receiving site in Saint John, New Brunswick, for imported gas from Trinidad and Tobago and Qatar—but there are plans for exports of British Columbia and Alberta natural gas piped across the Rocky Mountains to the Pacific coast with LNG terminals in Kitimat and Prince Rupert (LNG Canada, 2014). Both the timing and eventual magnitude of these shipments from the West Coast to Asia are highly uncertain, as even the requisite pipelines face a great deal of opposition by environmentalists and by Canada’s aboriginals who are asserting their legal claims for land, and even for offshore waters, in their determination to stop any new development.
In any case, plans for the US LNG exports are much bolder. Expected dates for start-ups of already approved US export projects are Sabine Pass, LA, and Elba Island, GA, in 2016; Freeport, LA, Cove Point, MD, and Sabine Pass (Phase II) in 2017; and Lake Charles, LA, and Sabine Pass (Phase III) in 2018, and if all the pending proposals were to be approved, America’s future LNG exports could be close to 50 Mt LNG by 2025 and eventually approach 200 Mt/year (compared to Qatar’s 77 Mt in 2013). But how many US projects will be eventually approved and how many of those will actually go ahead? While new brownfield LNG plants in the United States may have acceptable costs, it is far from certain that, as Weissman (2013) and others have claimed, the country is getting positioned for the dominant role in global LNG markets. Reaching that goal would depend on continued low or only mildly increased prices, but it does not strain credulity to think that the combination of growing domestic demand (caused by expanded gas-based electricity generation and new petrochemical capacities) and rising LNG exports could bring substantially higher prices (Ratner et al., 2013).
Could this unwelcome trend be hastened by concluding an excessive number of export agreements (currently there are nearly 40 applications to sell LNG abroad) that would reduce the number of new petrochemical projects whose construction rests on cheap natural gas? Dow Chemical thinks so, and the company has argued for restricted exports in order to protect domestic supplies (Helman, 2012). If most of the contemplated projects were to go ahead, the United States would become not only a major exporter but perhaps even the world’s top seller of natural gas—but such a forecast seems to ignore the likely moves of other major gas exporters: becoming the top exporter of LNG is a goal that does not depend on the United States alone because whatever the United States does to advance that development could be affected, even negated, by the moves of other key global LNG players.
The largest LNG market in Asia (with Japan, China, South Korea, and Taiwan as the largest buyers) is now served by exports from Australia, Indonesia, Malaysia, and Qatar and by pipeline exports to China from Turkmenistan, Uzbekistan, and Kazakhstan. As already noted, the agreement reached in 2014 to supply China for 30 years with Siberian natural gas was a true strategic shift: annual volume of that contract is nearly as high as China’s total (pipeline and LNG) gas imports in 2012, yet its price is lower than Gazprom’s sales to Europe. Before this agreement was concluded, its volume could have been counted as a potential need to be filled by imported LNG, and if another similar agreement will be signed in 5 or 10 years, the volume of LNG imports China will seek from across the Pacific would decline further.
And is it reasonable to expect that Russia’s Gazprom, the world’s largest exporter of natural gas, would continue to insist on high long-term contract prices as th
e United States starts shipping significant volumes of LNG into Europe’s ports? And what is Russia’s long-term role in LNG trade? So far, Gazprom has been only on the fringes of global LNG trade with its Sakhalin project (gas deliveries to Japan started in March 2009), but the country has enormous Siberian gas reserves whose transportation to East Asian markets could be eased by Arctic warming. Would Gazprom simply stand aside and, after developing its Sakhalin reserves for exports to Japan and South Korea, concede the LNG market to others and concentrate only on pipeline shipments?
Hardly so, in 2012 LNG tanker Ob River charted by Gazprom completed the world’s shipment via the Northern Sea Route, starting in Hammerfest, Norway, on November 7 and arriving at Tobata, Japan, on December 5 (Gazprom, 2012). Ice-breaking LNG tankers could access new resources of Arctic gas, already appraised to supply at least 30–40 Mt/year. And Russia’s other large gas producer, Novatek, is developing (with state subsidies and together with France’s Total and China’s CNPC) a large LNG project on the Arctic’s Yamal peninsula (South Tambeyskoye Field) that is valued at $27 billion and that would help to double Russia’s share of global LNG market by 2020 to nearly 10% (Novatek, 2014a).
And would Qatar, the world’s leading LNG seller and the owner of the largest and most modern tanker fleet, just stand by and watch as the tide of US exports reduces its European and Asian market shares? Would Australia, with its rich reserves and established Asian markets, abstain from competing for shipments to China and Japan? And how rapidly could large US LNG exports going to Europe change the EU’s supply that has been dominated by Russia, Norway, the Netherlands, and Qatar? Would Gazprom, with its enormous sunk cost in long-distance pipelines from Western Siberia to the EU, just continue to insist on expensive and inflexible long-term contracts or would it try to undercut the US LNG exports to European ports?
And, ultimately, there is Iran, the country with the world’s largest (and overwhelmingly undeveloped) conventional natural gas reserves. Eventually, Iran will become a normal country, not a theocracy ruled by fundamentalist mullahs. Such fundamental breaks seem always unthinkable, but they are bound to happen (just recall rapid transformations of power in the USSR, Egypt, or Myanmar), and if the country’s hydrocarbon resources were to be developed with the benefit of the best foreign knowledge and technical assistance, its natural gas sales could easily surpass Qatar in total output and vie with Russia for global export primacy.
And given the widespread distribution of shales, almost every one of today’s major LNG producers and many of today’s LNG buyers will have to decide how far (if at all) they will go with their development and what balance they will eventually strike between increased domestic production and imports. Not surprisingly, by the end of 2014, many potential Asian buyers of the US LNG appeared to be much less enthusiastic about the future of such imports, reselling their quotas and reducing their commitments. And while there is no doubt that the progress toward a truly global, LNG-enabled, natural gas market will continue, the cost of new large LNG projects and inherently more expensive and less convenient transportation and storage of the fuel make it unlikely that the worldwide gas market will be as flexible as its crude oil counterpart.
Contradictory claims and disputes regarding hydraulic fracturing and new LNG systems will not be resolved in a year or two. We should be able to form a much more solid appraisal before 2020: by that time, intensive hydraulic fracturing in the United States will have accumulated more than a decade of intensive operation in every major shale formation, and as tens of thousands of wells will have yielded most of their expected ultimate recovery, we should be able to make a much more confident appraisal of long-term shale gas prospects. Moreover, by that time, environmental problems associated with shale gas extraction will have been either effectively managed or they will become a substantial drag on further development, and a new, truly global, LNG infrastructure will, or will not, have largely taken shape.
8.4 UNCERTAIN FUTURES
A seemingly strong consensus is no reliable indicator of future developments: it may be quite correct, but it is much more likely that actual developments will depart significantly from the anticipated course because the prevailing appraisals will miss some major developments and even many more less obvious but cumulatively critical shifts and adjustments. Evolution of modern energy systems illustrates all of these developments, ranging from richly fulfilled expectations of electricity’s transformational role in lighting to hugely exaggerated hopes for nuclear generation. Recent consensus about the global future of natural gas is certainly not as uncritically unrealistic as were the hopes for nuclear fission in the early 1970s (consensus saw it as the dominant, if not the sole, mode of electricity generation by the century’s end), but it is also far from being a matter of subdued expectations.
The International Energy Agency went all the way, asserting that “natural gas is poised to enter a golden age” (IEA, 2012); General Electric stayed away from adjectives and entitled its survey The Age of Gas because the fuel “is poised to capture a larger share of the world’s energy demand” (Evans and Farina 2013, 3). And common descriptors encountered in papers, reports, and books dealing with natural gas have included repeatedly revolution, renaissance, boom, bonanza, and transformation. And the MIT natural gas study highlighted the role of natural gas as “the cost benchmark against which other clean power sources must compete to remove the marginal ton of CO2” and as “a cost-effective bridge to a low-carbon future” (MIT, 2011, 2).
I will adhere to my steadfast refusal to engage in any long-term forecasting, but I will restate some basic contours of coming development before I review a long array of uncertainties whose eventual resolutions could all have, directly and indirectly, major consequences for global and national extraction and conversion of natural gas. Perhaps most importantly, and contrary to many overenthusiastic recent appraisals, rising extraction of natural gas still has a long way to go before the fuel becomes to rival its solid and liquid fossil counterparts. A key reality is worth stressing once more: global transition from coal and oil to natural gas has been proceeding at a slower pace than the two previous great transitions from coal to oil and from wood to coal.
After it reached 5% of the global fossil fuel market, crude oil needed 40 years to reach 25%, while natural gas needed about 55 years to reach the same level. And if the fuel shares are expressed in terms of total primary energy supply (including all primary electricity and commercial biofuels), then crude oil peaked at about 48% in 1973, but natural gas is yet to reach 25% of the global total. Given the scale of existing energy demand and the inevitability of its further growth, it is quite impossible that during the twenty-first century, natural gas could come to occupy such a dominant position in the global primary energy supply as wood did in the preindustrial era or as coal did until the middle of the twentieth century.
Indeed, it is highly unlikely that even by 2050, the share of natural gas in the world’s energy use would reach the peak that was attained during the 1970s by crude oil. And in cumulative energy terms, during the twentieth century, natural gas was the distant third fossil fuel: coal supplied about 43% of all fossil energy, crude oil about 37%, and natural gas 20% (Smil, 2010a). Cumulative output during the second half of the twentieth century saw coal and oil switching places (coal at 36%, crude oil at 43%), but natural gas rose only to 23%. Again, it is unlikely that natural gas will supply, in aggregate, more energy during the first half of the twenty-first century than either coal or crude oil.
And if the first decade of the twenty-first century was a trendsetter, then all fossil energy sources will cost substantially more, both to develop new capacities and to maintain production of established projects at least at today’s levels. The IEA concluded that by 2013, capital costs of energy production have more than doubled in real terms (to $1.6 trillion) when compared to the year 2000 (IEA, 2014), and obviously, such large investments lock in the composition of primary energy use and consequence of such usage. Th
e IEA estimates that between 2014 and 2035, the total investment in energy supply will have to reach just over $40 trillion if the world is to meet the expected demand, with some 60% destined to maintain existing output and 40% to supply the rising requirements. The likelihood of meeting this need will be determined by many other interrelated factors.
Combination of long lead times needed to develop new fuel extraction capacities and to build requisite processing and transportation infrastructures, and of rising costs of those facilities requiring long-term financial commitments mean that there can be no production surprises. And the principal actors and their roles also change slowly: as IGU (International Gas Union) (2012, 5) rightly concluded, “the rigid, long-term nature and economic impact of international gas transactions not only require more government involvement on both the producer and consumer end—and in any other transit country—than other forms of international energy transaction, but may also stir up wider political interest.”
Consequently, we have a fairly good understanding of what will take place during the next 2 or 3 years—with the usual proviso that even short-term confidence can be shattered, or at least much modified, by major international conflicts, by another substantial global economic downturn, or, least likely, by a crippling pandemic or an encounter with an asteroid. But forecasting even a decade ahead multiplies the uncertainties that have been made fundamentally more interrelated by the new nature of interdependent global economy and politics that has been reshaping the basic contours of post-1945 international order.
Here is a far from exhaustive list of factors that have a high probability of affecting (be it positively or negatively) the world’s natural gas supply in near term (during the next 5–10 years). A large number of these factors concerns hydrocarbon resources and technical advances in their recovery and conversion. Extent of the US shale gas production (continuing rise, an early plateau, and unexpected decline) will make long-term prospects much clearer. Progress of shale gas extraction in other countries, above all in China (lifting of fracking bans; aggressive pursuit in several countries), would indicate if shale gas will remain largely a North American phenomenon or if it will become a global fuel. Decline of conventional oil reserves and the success in large-scale recovery of nonconventional oil will determine the supply or shortfall of liquid hydrocarbons that could be partially or largely substituted (via GTL conversions) by gas. Reduction of fuel demand due to continuous rise of conversion efficiencies, both in stationary applications and in transportation, would moderate demand for all hydrocarbon fuels.