Gas production in the U.S. hit a rough patch this year due to low prices. Yet its future looks bright, considering the potential of Asian markets, which are significant importers of blue gold, and the E.U. market, where it competes with Russian gas
The U.S. shale revolution began less than a decade ago, and 2016 has proven to be the industry’s most challenging year. In 2016, oil prices have fallen below $30 per barrel in the early months, projected capital expenditures in the U.S. have declined by roughly 40 percent year-on-year (y-o-y) and U.S. gas rig counts have dropped by nearly 60 percent y-o-y. In fact, a confluence of factors is challenging U.S. gas production today. The significant decline in oil prices since 2014 has not only slowed drilling activities by reducing the profit margins for oil and gas producers and thus the levels of capital spending, but also weakened the value of associated liquid from gas drilling that had been an important source of revenue for producers.
Additionally, low domestic gas prices in the range of $1.50 to $3.00 per million British thermal unit (mmBtu) stressed the economics of gas production in the United States. According to the most recent data by the U.S. Energy Information Administration, the average U.S. marketed gas production for 2016 (per the Short Term Energy Outlook, released on November 8) was 77.3 billion cubic feet per day (bcf/d), a 1.4 percent decline year-on-year. Furthermore, the United States has seen no Final Investment Decision in liquefied natural gas (LNG) projects this year. Yet, the year was far from a disaster.
A very good year for America
In February, the United States made the first export of LNG from the lower 48 states. The LNG shipment from Cheniere Energy’s Sabine Pass LNG terminal in Louisiana ushered in a new era for the U.S. gas industry. This first shipment was well worth the substantial scrutiny and regulatory hurdles that the first mover project had to undergo as it turned the existing import infrastructure around for LNG exporting. From a national perspective, the shipment marked the beginning of the U.S.A.’s emergence as a net exporter of domestically sourced natural gas as early as next year, and more significantly, as the third largest holder of LNG export capacity by 2020. As of October 2016, over 30 LNG cargos had already departed the Sabine Pass LNG export facility, and five projects—or about 63 million tons per annum (mta) of export capacity—are under construction.
Another key development this year was the opening of an expanded Panama Canal in June. After a commitment of more than U.S.$5 billion and nearly a decade of construction, the canal gained an additional lane as well as greater width and depth to the existing lanes. The expansion has enabled the canal to accommodate 90 percent of the global LNG tanker fleet, from about 6 percent pre-expansion. What’s more, transiting through the Panama Canal post-expansion shortens the voyage time for U.S. LNG from the Gulf Coast to markets in Northeast Asia and South America. According to the U.S. Energy Information Administration (USEIA), the LNG shipment from America’s Gulf Coast through the Panama Canal to Japan will take 20 days, compared to 34 days for a journey around the southern tip of Africa or 31 days for a journey through the Suez Canal. Also, the Panama Canal can reduce voyage time to Columbia and Ecuador from 25 days to 5 days, and to Chile from 20 days to 8-9 days.
In the time of reduced price differentials between oil-linked LNG prices and U.S. domestic gas prices, lower transportation costs resulting from savings on fuel oil, boil off and labor are nothing to take for granted. The price environment was in fact quite different earlier in the decade, when many Asian companies, including KOGAS of Korea, GAIL of India and several companies from Japan, made investment decisions, and the U.S. LNG export projects were sanctioned. For example, major Japanese electric utilities, gas companies and general trading houses together committed themselves to U.S. LNG volume equivalent to 20 percent of Japan’s annual gas import levels. Even after costs incurred for liquefaction and shipping raised the price of U.S. LNG delivered to Asian markets, the Asian importers who were paying about U.S.$16 per mmBtu believed there would be sufficient price differentials to warrant such commitments.
It is the flexibility of U.S. LNG that appeals
However, it was not just low domestic gas prices that attracted the Asian buyers to U.S. LNG. In contrast to the traditional model of LNG export project development or contracts, U.S. LNG offer substantial flexibility. Gas markets in the United States are highly liquid and transparent, and U.S. LNG export projects do not require oil-linked price or natural gas production by LNG plant owners to be able to recover on capital investments for developing upstream or export infrastructure. Instead, most of the U.S. export projects offer LNG contracts with Henry Hub spot gas based pricing and no obligation to the customers to take ownership of the gas when prices are too high and thus unattractive abroad—as long as they pay a fee (or ‘toll’) for the contracted liquefaction capacity they did not use. Moreover, this so-called tolling model provides off-takers with destination flexibility although it also shifts the risk of gas price volatility to the off-takers.
These flexible features, backed by the current state of LNG surplus, have already emboldened customers in Asia and elsewhere. For example, JERA of Japan—a joint venture between Chubu Electric Power Co. and Tokyo Electric Power Co., whose purchasing power accounts for about 40 percent of Japan’s LNG imports—plans to stop signing LNG contracts with destination clauses and to significantly reduce the share of long-term LNG contracts in its portfolio in the coming decades.
Korea has expressed its intent to secure more flexible terms and exclude destination clauses in re-negotiating the expiring LNG contracts. Moreover, there are efforts to create a hub or two for LNG trading in Asia as a means to enhance LNG trading liquidity and transparency, as exemplified by the launch of “SLInG” price by Singapore in 2015 and the Japanese publication of a roadmap for LNG hub creation as part of their LNG Strategy announced at the G7 Energy Minister’s Meeting in Japan in May of 2016. Additionally, Japan’s Fair Trade Commission, keenly aware of the European Commission investigation into Gazprom’s anti-competitive business practices in European gas markets, is examining if the destination clauses in Asian LNG contracts impede competition laws.
Asian buyers were not to be the exclusive beneficiaries of these flexibilities. The destination flexibility in U.S. LNG led many shipments from the Sabine Pass project to travel to a variety of markets that were not so obvious in the years leading up to the oil price collapse in 2014, as spot LNG prices in Asia and Europe declined to US$4-5 per mmBtu this year. In fact, roughly half of the total cargo shipped to date from the Sabine Pass terminal has gone to South America, with several shipments each to Europe and the Middle East. For example, the first LNG shipment of the Lower 48 gas in February went to Brazil, by the 160,000 bcm carrier called—incidentally—Asia Vision. Free of destination restrictions common in traditional LNG contracts, U.S. LNG can be shipped to wherever market conditions are right.
An important implication arises for U.S.-E.U. energy relations as much from the future of Asian demand as from future gas prices. Asian gas demand affects the pace and volume of U.S. LNG reaching European markets and consequently affects policymaking and priority-setting by public and private sector leaders relative to Europe’s sense of energy security. However, the policy circumstances and domestic market conditions that shape the role of natural gas are in flux in some key Asian markets. In the established LNG markets in Asia, not only the inter-fuel competition but also declining electricity consumption growth—driven by weak manufacturing growth and demographic changes—are leading to wide divergence in gas demand outlooks.
The case of Japan, the world’s top LNG importer
In particular, Japan, the largest LNG importer country in the world, faces a serious demand uncertainty due to the slow pace of nuclear restarts (despite the Japanese government resolve to revive the country’s nuclear power generation program). The Fukushima accident reversed Japan’s status as a mature and perhaps saturated LNG market to that of a strong demand center, as Japan increased its LNG import volumes by 24 percent in an effort to meet the shortfall in power generation capacity from nuclear outages. Between 2012 and 2014, Japan’s market share of the global LNG demand increased to an average of 37 percent, from 31 percent in 2010, which was the lowest in four decades. If all works according to the government vision under the 2014 Strategic Energy Plan, the share of nuclear energy would return to 20-22 percent in the nation’s power supply outlook by 2030 (which is a little below the pre-Fukushima 10-year average) while the share of LNG would decline from the post-Fukushima high of 43-44 percent to the pre-Fukushima 10-year average of 27 percent, or to 18 percent in the primary energy supply (about 62 mta of imports) by 2030.
These targets are quite challenging in light of continued public concern over nuclear safety, however. As of early November, Japan’s 54-reactor fleet pre-Fukushima has shrunk significantly after 15 units were slated for permanent shutdown and about 20 units remain under regulatory safety review necessary for restart; a majority of the remainder have passed the safety review but await final technical steps before resuming operation. Absent steady construction of new units or proactive extensions of operational license beyond 40 years, the nation’s nuclear fleet could shrink to about 15 percent of the electricity supply mix by 2030 and be nearly extinct by 2040. Additionally, the revival of coal use renders the future level of Japanese reliance on LNG uncertain. Between 2010 and 2014, Japan’s coal consumption increased by 19 percent, primarily to fill the gap left by nuclear outage. As deregulation efforts in the power and gas sectors heighten competition among electric power companies, gas companies and new entrants, coal appears to be gaining interest by those entities that seek a low-cost electricity source. Insofar as LNG imports go, U.S. LNG free of destination restrictions may be particularly attractive to Japanese buyers who face such a degree of demand uncertainty.
The Korean and Chinese markets
The inter-fuel competition in the power sector is also rendering LNG import needs uncertain for Korea, which is the second largest importer of the global LNG supply today. Korea’s net LNG import level has been on a steady decline in recent years, from 40.86 mta in 2013 to 37.98 mta in 2014, and to 33.36 mta in 2015, according to the International Gas Union. Meanwhile, Korea is planning on building 20 new coal plants by 2020, and increasing nuclear generation capacity by 70 percent by 2029. Insofar as the government favors coal-fired generation and nuclear power generation in the coming years, Korea may feel much more inclined to stay away from long-term contracts.
The outlook for demand growth is stronger for emerging economies in Asia. Despite demand growth slowdown since 2014, natural gas has a strong growth potential in China as the fuel is seen as one of the viable energy sources to help reduce the country’s heavy dependence on coal and to alleviate the attendant environmental and climate ills. For example, China strives to raise the share of natural gas in primary energy consumption to 10 percent by 2020 (The 13th Five-Year Plan). Today, LNG accounts for only half of the country’s import needs, which in turn meets one-third of domestic gas needs.
However, since China began importing LNG in 2006, its net imports have grown rapidly, from 9.47 mta in 2010, to 18.6 mta in 2013, to 19.83 in 2015, according to the International Gas Union. In the near term, the existing long-term contracts will be the source of strong LNG import growth. However, the longer term outlook for LNG needs and the role of U.S. LNG in China depend on a number of factors, including the potential commercialization of domestic unconventional gas resources, the degree of reliance on pipeline gas imports (including the scope of future imports from Russia), as well as more macro-level questions, such as the degree of economic slowdown, structural changes from more energy intensive pathways for economic growth to less intensive pathways, and the extent of carbon emissions reduction. To the extent that U.S. LNG is free of destination restrictions and travel to where market conditions are right, we might see a steady flow of U.S. LNG to China in the future. For example, in late August, U.S. LNG from the lower 48 arrived in China after becoming the first LNG shipment to transit through the expanded Panama Canal.
American LNG destined to Europe
A limited volume of U.S. LNG shipped to Europe since the beginning of this year. However, weak global economic growth in developing countries and low LNG prices have already made LNG a competitive alternative to pipeline gas in continental Europe. For example, in December 2014, Italy paid an average of U.S.$9.61 per mmBtu for pipeline gas and U.S.$9.01 per mmBtu for equivalent LNG supplies, while Spain paid an average of U.S.$10.02 per mmBtu for pipeline gas and US$8.97 per mmBtu for equivalent LNG supplies, according to the European Parliament. In fact, the global LNG industry is entering a period of oversupply as export capacity ramps up in Australia, Southeast Asia as well as the United States, adding about 160 bcm of capacity through 2020. U.S. LNG later in the decade has a great potential to enter European markets in a substantial manner, particularly if the moderate appetite in Asia leaves only a little room for U.S. LNG.
In the oversupplied market, LNG supplier countries, such as Australia, Malaysia and Indonesia, will likely benefit from the proximity advantage over U.S. LNG in Asian markets, prompting more U.S. LNG to flow to European markets. One consequence of this may be for U.S. LNG to come into competition with Russian gas, which plans to retain about 30 percent of the European gas market for the next two decades. Yet, the outcome of such competition is difficult to predict as it is greatly subject to global oil prices and U.S. domestic gas prices. Not to mention Russia’s game plan—particularly regarding Gazprom; the company could choose to reduce the price of its gas to Europe to as low as US$3.50 per mmBtu in an effort to block the substantial arrival of U.S. LNG, and/or expand pipeline connections to Europe to capture more buyers in the longer term.
Notwithstanding questions like how long oil prices may remain relatively low and how long U.S. LNG projects can operate on the basis of variable costs, the future of U.S.-EU energy relations portends opportunities. The reduction in U.S. LNG imports and the advent of robust U.S. LNG supplies are already helping to elevate the role of natural gas in energy security dialogues in Europe. Provided that adequate infrastructure is available to facilitate LNG imports and intra-regional gas distribution, U.S. LNG can be an undeniable asset for Europe’s effort to diversify gas supply sources and to enhance regional energy security, either directly through volume or indirectly through added global liquidity and contractual flexibility. The history is still being written for the U.S. shale revolution, and 2016 seems to be only one of the earlier milestones in what may prove to be a long chapter.
石油圈
