While hopes for more robust shale production at a global level have not yet been realized, markets became awash in natural gas for other reasons. On the supply side, other natural gas projects long in the works added new output to the market. On the demand side, as mentioned, slower economic growth and competition from coal and renewables particularly in China caused demand to be less robust than predicted. Given this situation, the world did not work off the gas overhang as IEA predicted it would by 2015 in its gas-friendly scenario. Instead, in 2016, talk of an enduring natural gas glut persisted, with the IEA and others predicting a deepening glut in the coming years as even more U.S. and Australian LNG exports come online.
Looking ahead, natural gas still is a good fuel upon which to bet. It is the only fossil fuel whose share of the energy mix is expected to rise over the coming decades according to mainstream projections. Moreover, even in scenarios where the creators present a future in which the world has become much more serious about the challenges of climate change, natural gas either maintains its share of global energy use or increases it.
There are, however, some early signs that natural gas could end up falling between two stools, at least in certain parts of the world. Either of two policy extremes could bode badly for natural gas. If the world—Asia in particular—becomes more lax about its use of coal, natural gas will be the fuel to lose out; without some policy interventions, coal remains dramatically cheaper than natural gas in most parts of the world outside the United States. On the other end of the spectrum, should the world become more aggressive in its efforts to combat climate change, policies could shift the calculus in favor of renewables, at the expense of natural gas.
While the IEA’s golden age of gas has certainly not arrived globally, the changes in the world of natural gas have still been extraordinary. As with oil, there is a story about burgeoning supplies, largely attributable to tremendous technological advances. And there is the punctuation of a price collapse—no less dramatic, even if less publicized, than the oil price plunge from 2014 to 2016. And finally, as is the case of oil, there are a host of other changes—to markets, pricing arrangements, and business models—that collectively have and will continue to have a critical impact on geopolitics.
Technology Transforms
On a hazy Sunday toward the end of February 2016, four red, white, and green tugboats maneuvered the 935-foot, 100,000-ton Asia Vision tanker into position. The valves of the tankers had to be lined up precisely with the four loading arms of the jetty at Sabine Pass terminal, part of a one-thousand-acre facility straddling the Texas-Louisiana border. With a wrench the size of a human arm, workers secured the ship to the jetty. Natural gas, which had been cooled to –260 degrees Fahrenheit and liquefied over the course of traveling through more than a mile of steel pipe and refrigerating systems, flowed into the tanker. A few days later, at 7:39 p.m. on February 24, flying under the flag of the Bahamas, the Asia Vision departed Sabine Pass and began its voyage to deliver its three billion cubic feet (bcf) of natural gas to Brazil.
As routine as it might sound, this scene was historic. For Cheniere, the American company that had spent more than a decade and close to $20 billion to develop the Sabine Pass LNG facility without ever turning a profit, it was a day for celebration; the Asia Vision was the first vessel carrying LNG that had shipped from the lower forty-eight states since the 1960s. After decades of fretting about its burgeoning dependency on imported energy, the United States had become an exporter of natural gas.
Two drivers lay behind the new age of oil abundance explored in previous chapters. The first was technological as new extraction techniques such as fracking emerged. The second was geopolitical and came in the form of the weakening of OPEC. Together, these technological and political factors transformed the future of oil for the next decade or longer. Similarly, in the case of natural gas, there have also been two drivers of the new energy abundance—both, this time, in the field of technology.
The first is the technological advances that enabled the shale boom to emerge in North America. Although we explored these innovations in earlier chapters, it is worth once again marveling at the scale of the development in natural gas. Well into the 2000s, policymakers and strategists fretted over a growing U.S. dependency on imported natural gas, not only from Canada, but also from suppliers in Africa, South America, and even, potentially, Russia. Tapping the vast quantities of shale gas in the United States spurred a massive turnaround in America’s natural gas trajectory. In 2000, the United States was producing virtually no shale gas. Just ten years later, shale production had crept up to be a quarter of the total. By 2016, shale accounted for a full 53 percent of all U.S. dry natural gas production.
Looking beyond the United States, shale gas reserves are even more ubiquitous than those of tight oil. The U.S. EIA has already assessed forty-six countries for their shale gas potential. It found that, in those countries, global shale gas resources are massive. According to those initial estimates, they roughly equal the conventional natural gas resources of the Americas, Europe, and Eurasia (including Russia). If we include other types of unconventional gas in our calculations, such as tight gas and coal bed methane, global unconventional gas resources amount to nearly four-fifths of the conventional gas resources of the whole world.
While the IEA has dialed back the timeline in which the golden age of gas will be realized, the Paris-based agency still anticipates the unconventional gas boom going global. Given the difficulties of replicating the American shale boom elsewhere, the United States will be the producer of nearly all the world’s shale gas in 2025. By 2040, the United States will still be dominant, but other producers will likely have emerged apart from the United States and Canada. Australia, China, and Argentina are expected to lead the pack, but Mexico and others may not be far behind. By some assessments, by 2035, China could bring more new shale gas to market each year than any other country.
The second technological development that has recently transformed the role of natural gas in the world actually began back in the eighteenth century with a British scientist named Michael Faraday. Born into a poor family of ten children in 1791, Faraday received little formal education. However, at the age of fourteen, he became an apprentice to a French bookbinder, who permitted him to read the books on which he was working. Faraday began a voracious process of self-education and scientific experimentation, including the first successful effort to liquefy gas in 1845. In its liquefied form, gas only takes up 1/600th of the space it would otherwise, creating obvious advantages for its transportation. Yet it was not until nearly a century later that the first commercial LNG plant was built in Cleveland, Ohio, and nearly another two decades before the Methane Pioneer, a converted World War II liberty freighter, transported a cargo of LNG from Louisiana to Great Britain.
Despite the success of this shipment and a dozen others that followed in its wake, LNG remained a niche fuel for the next forty years, with the vast majority of LNG exports feeding the energy-hungry island nation of Japan. Virtually all other natural gas was still transported through pipeline networks. After 1990, however, technological advances, such as increases in both the size of tankers and liquefaction trains, brought down the cost of LNG. In 2005, a new innovation—called a floating storage and regasification unit (FSRU)—was first deployed in the American Gulf of Mexico. Either purpose-built or converted from an LNG vessel, these units opened up possibilities for more countries to meet their gas demand through LNG. Jordan is one case in point.
The revolution sweeping through Egypt in 2011 and its aftermath had practical implications for its neighbors in more than one way. Jordan, a Middle Eastern country bereft of big energy resources, had long imported natural gas from Egypt via the 750-mile Arab Gas Pipeline snaking its way from the Egyptian delta through the Sinai Peninsula into Jordan and Syria. Instability in Egypt led to repeated attacks on this pipeline and ultimately the suspension of gas supplies to Jordan. Seeking a comparatively quick solution, J
ordan negotiated for a FSRU to be docked in its Red Sea port of Aqaba, allowing the kingdom to accept LNG and address its gas shortages more quickly than had it needed to build new infrastructure.
Other countries, particularly those with smaller markets or geopolitical, political, or financial circumstances that make it difficult to secure funding for large investment projects, have also opted for FSRU units. Now, according to Leslie Palti-Guzman, head of global gas at the Rapidan Group, “you can be an LNG importer in 18 months, even if you don’t have the infrastructure and you aren’t creditworthy.” If a country defaults on its payments, its creditors can simply reclaim the facility as collateral. These advances have made buying LNG more flexible and less capital intense to use. They require less commitment from a country that might be unwilling to invest in expensive infrastructure it hopes it will not need in future decades. In short, they have made natural gas more like oil.
Countries such as Egypt, Pakistan, and Turkey also saw these advantages and opted to build FSRUs, thereby contributing to the boost in the number of countries importing LNG—from ten to thirty-five—between 2000 and 2016. During that same time, global capacity to regasify the liquid fuel increased more than twofold and overall LNG trade more than doubled. LNG had become mainstream.
Figure 3.1: LNG Trade Volumes, 1990–2016
1 Excluding Indonesia, which buys cargoes exclusively from domestic liquefaction plants.
2 The United States is included in both totals, since it exports domestically produced LNG from Kenai LNG in Alaska and re-exports LNG from regasification terminals in the Gulf of Mexico.
Source: International Gas Union, IGU World LNG Report, 2017, 7.
The future for LNG looks even more robust than its recent past, particularly if the drop in its price is arrested. In the next two decades, LNG trade is poised to take on an ever-larger slice of the fast-growing pie of the overall global natural gas trade. In an absolute sense, the IEA projects the volume of LNG trade will more than double again. Remarkably, nearly half this growth in LNG supplies is expected to occur before 2020. According to BP, LNG volumes will in fact expand seven times faster than gas transported by pipe, and, by 2035, account for close to half of all globally traded gas.
The advent of U.S. LNG, made possible by shale gas, and Australian LNG, much of which is sourced by another unconventional gas called coal bed methane, are two major drivers of this expected surge. Much of the Australian LNG under development will surely make it to global markets given the huge investments already made before prices sank. There is, however, more uncertainty about the size of the expected wave of U.S. LNG.
Estimates of how much LNG America will export in the years ahead have varied, and are highly dependent on a price robust enough to make the trade commercial. Although the price of natural gas is so much lower in the United States than in most other parts of the world, the costs of liquefying the gas, transporting it long distances, and regasifying it upon arrival also need to be factored in when a potential consumer considers U.S. LNG as an option. Assuming these costs are between $5 and $8 per one thousand British thermal units (mmbtu), if the Henry Hub price of gas in the United States is around $4 per mmbtu, then prices in Asia or Europe would need to be $9 to $12 per mmbtu for the trade to be profitable. Some countries may desire to have U.S. LNG imports in their energy mix for reasons of diversification or because they see the United States as a reliable supplier. But because companies, not countries, make decisions about individual contracts, trade will occur where and when these companies see a market opportunity.
It is primarily these uncertainties that will determine just how much LNG the United States will bring to market. If all the applications to export U.S. LNG received by the U.S. Department of Energy for approval as of July 2016 materialized and these facilities were fully utilized, they would result in more than 58 bcf of new LNG added to global markets each day; that is nearly twice the entire global LNG trade in 2015 and five times the LNG imported by Japan, the largest LNG importer in the world, in the wake of the Fukushima tragedy in 2013. This large quantity of U.S. LNG will certainly not be commercial. Yet the volumes are set to rise from the trickle of exports in 2017 to a steady flow. According to the U.S. EIA, in 2020 the United States will be home to nearly one-fifth of global liquefaction capacity and the third largest LNG exporter in the world after Qatar and Australia.
Boon to Consumers
More superficially, there is another way in which natural gas has more closely resembled oil in recent years: the price of natural gas plunged markedly from 2014 to 2016. Thanks to American shale gas, the price of Henry Hub sank below $2 per mmbtu in the first half of 2016, down from a monthly peak of more than $13 in October 2005. European and Asian natural gas markets also experienced striking price collapses, but for different reasons than occurred in the United States. The price to import natural gas into the European Union dropped from nearly $13 per mmbtu in April 2013 to $4 in May three years later. In Asia, where roughly 70 percent of LNG trade occurs, LNG prices were sliced in half from Valentine’s Day to Thanksgiving in 2014. In Japan, the price of importing LNG fell further—from over $16 per mmbtu in 2013 to just under $6 in 2016.
Figure 3.2: Monthly Average Regional Gas Prices, January 2010–January 2017
Source: International Gas Union, IGU World LNG Report, 2017 edition, 16.
At one level, the increase in global supplies would seem enough to explain the plummeting of these prices. Yet slower-than-expected demand—thanks in part to the financial crisis—also added to the trend. Moreoever, in Europe and Asia, where prices are partially or largely linked to oil prices, the drop in the price of oil quickly forced down the price of natural gas as well. European consumers also benefited from LNG cargo displaced by the American shale gas boom. As a result of the evaporation of U.S. demand for LNG imports from abroad, LNG exports intended for—but no longer needed by—the United States flowed instead first to Europe and later to Asia. Their arrival gave European utilities the leverage to renegotiate the price they were paying companies in Norway and Russia, in particular, for natural gas from pipelines, even under existing long-term contracts.
Yet even more was at work than these factors, with some of the additional developments poised to outlast the dip in prices. One significant change has been made to how natural gas prices are determined. The negotiation efforts of European utilities were not solely directed at the absolute price they would pay for natural gas. They also, successfully, used the moment to pursue a goal they had sought for a long time: jettisoning “oil indexation.” Tying the price of natural gas to that of oil was a practice developed by Jan Willem de Pous, the Dutch minister of economic affairs half a century earlier. The simplicity of this linkage made sense when de Pous proposed it in 1962, given that natural gas was often substituted for oil in the heating of homes and the generation of power. The pricing practice, however, persisted long after this rationale disappeared, in large part because producers such as Russia found it advantageous. It was only when U.S. shale gas production forced more LNG unexpectedly into Europe that utilities acquired the leverage to negotiate a price formula that placed more weight on “gas-on-gas” pricing and less on the price of oil. From 2005 to 2015, the amount of natural gas trade in Europe that was indexed to the price of oil declined from more than three-quarters to less than one-half. In Asia, the shift was less dramatic, but still significant.
Critical changes to natural gas markets extend far beyond just how natural gas is priced. Increasingly, the very distinct three regional markets of North America, Europe, and Asia are becoming more integrated. Because of transportation, infrastructure, and other such costs, the three markets will never completely merge into one market—like the one that exists for oil. But what happens in one gas market is increasingly affecting what happens in the other two; the market is becoming more globalized. As piped gas accounts for a smaller percentage of overall trade, gas is flowing more easily from one market to another, meeting demand as n
eeded.
In this more flexible, liquid market, more natural gas is being traded outside of long-term contracts—either on the spot market or through contracts lasting two years or less. The percentage of LNG traded in this fashion more than quintupled between 2000 and 2016; the number of countries exporting LNG on the spot market alone grew by five times in this time period. While the trend held in both Europe and Asia, it was much more pronounced in the first. Regional trading hubs are slowly beginning to emerge in Asia, allowing natural gas trade to be priced to better reflect supply and demand realities.
These trends toward greater fluidity in and between markets will accelerate in the years ahead, even if U.S. LNG only meets the most modest expectations. Yet, the transformative impact of U.S. LNG is not only a result of the increased volumes put on the global market. It also is a result of the rules and terms under which these exports will enter the market, which are much more flexible than previously traded LNG. First, the price of the overwhelming majority of U.S. LNG will not be indexed to that of oil. Instead, the base price for U.S. LNG—no matter its intended market—will be determined by Henry Hub, and therefore a product of gas supply and demand rather than oil price. Moreover, traditional global LNG contracts contain what are called “destination clauses” that restrict the ability of the buyer to resell any gas it has arranged to buy in its long-term contracts but no longer needs. This arrangement is good for producers, but less so for buyers. In contrast, U.S. LNG does not have these clauses, meaning that purchasers can resell the LNG if it makes sense to do so. Jonathan Stern, an Oxford University scholar and one of the leading experts on natural gas, predicted in 2016 that destination clauses will soon be a thing of the past. Already, consumers are resistant to signing contracts with such stipulations, signaling more changes to come in favor of even greater market flexibility.
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