Dynamics of natural gas pricing: the critical need for a natural gas hub in South Asia.

• Author: Kamal, Maha
• Position: Asia

This paper will examine three main pricing mechanisms for gas contracts: oil-indexation, gas-gas competition and netback from final product (e.g. prices linked to Ammonia etc.) in light of the gas contracts in this region that are oil-indexed or linked to oil prices. It will analyze the long term viability and competitiveness of this mechanism for South Asia and discuss natural gas demand in South Asia, conventional and unconventional sources of Natural Gas, as well as the effects of geopolitics in the region on Natural Gas contracts. Remaining cognizant of these developments, this paper proposes the creation of a new natural gas trading hub in South Asia.

Introduction

The natural gas market in the Asia-Pacific region is seeing great changes, as markets like Japan and South Korea mature and newer markets like India look towards different gas pricing mechanisms. As new players enter the market, existing literature on the subject indicates the need for greater competition and a break from old pricing mechanisms linked to oil. One of the most prolific experts on international gas pricing, Jonathan Stern, wrote that while hub pricing may be a solution for some markets, this solution may be unique for different countries: "In Asia, there is no reason to expect China and India to adopt price mechanisms identical to those of Japan and Korea." Similarly, the International Energy Agency proposed a new gas pricing hub in Asia, saying that a mature natural gas market may need more transparency.

The global natural gas market has seen many changes that have influenced the supply of natural gas, such as the Shale Gas Revolution in North America, the Fukishima disaster, Japan's increased demand for liquefied natural gas (LNG), and new entrants in the natural gas market through unconventional gas (shale gas, tight gas, coal bed methane etc.). While the Henry Hub in the U.S. is seeing prices in the range of $2-4 per MMbtu (million British thermal units, a unit for the heating value of natural gas), LNG prices in Asia have been as high as $18 per MMbtu in peak demand seasons. As global oil prices fell from their peak price of $115 per barrel in June 2014, the volatility of the oil market has been greater than the natural gas market. As the natural gas market continues to diverge from the oil market, oil-indexed contracts no longer reflect the realities of the natural gas market.

This paper examines the pricing mechanisms in Europe and the Asia-Pacific region, and analyzes oil-indexed contracts in comparison to gas-on-gas trade. It will then analyze the long-term viability and competitiveness of this mechanism for South Asia, and discuss natural gas demand in India and Pakistan, the two biggest natural gas markets in South Asia. Lastly, it looks at the geopolitics of natural gas for South Asia and the impact of some interesting changes that have not yet been explored in the literature.

This paper proposes the creation of a new natural gas trading hub in South Asia, to promote the liberalization of natural gas markets in South Asia, particularly in light of new political factors such as the Iran nuclear deal of 2015, the China-Pakistan Economic Corridor (CPEC) and the U.S. exit from Afghanistan.

It concludes that this may conservatively take more than a decade to develop since the evolution of natural gas pricing mechanisms took more than five years in Europe, and are projected to be longer for more mature Asian markets. South Asia as a whole is still a new entrant in the global natural gas market, and regional politics greatly influences infrastructure developments. However, this paper will argue for South Asian nations to work towards the creation of this natural gas trading hub, in order to a) reduce the impact of oil price volatility on South Asian economies; b) increase competition in the natural gas market; and c) promote regional integration through greater trade.

Global natural gas markets are changing

As global oil prices fell from their peak price of $115 per barrel in June 2014 (see figure 1), importing natural gas indexed to oil could not remain economically viable for oil-importing countries. With oil prices falling at a slower rate than natural gas prices in some hubs, old pricing mechanisms linked to oil were no longer competitive. (1) Since the ease of the global financial crisis in 2009, oil prices have steadily decreased. The average Brent Crude price peaked in 2011 at $117 per barrel, and fell roughly $17, to average $98.95 per barrel in 2014. With high volatility in 2015, average oil prices may be lower than 2014 prices at the time of this paper's publication. In contrast, natural gas markets are evolving in response to increased supply from shale gas, new LNG export terminals coming online, and expansion of LNG supply (for example, Papua New Guinea entered the market in 2014). (2)

Production and consumption of oil increased by a greater percentage than that of natural gas, and while this may have multiple factors, the effects of plunging oil prices on shale gas production cannot be understated, and may become even more pronounced post-2015. Once prohibitively expensive, hydraulic fracturing has been economically viable since 2009, and contributed to the shale industry's growth until June 2014, when falling prices affected the competitiveness of shale oil. As Figure 1 shows, from 2013 to 2014 the production rate of both natural gas and oil was greater than the consumption, which signals an imbalance in demand and supply.

Before the discussion progresses to the nature of natural gas markets, and before we delve into the specifics of natural gas pricing, it is crucial to discuss some types of natural gas contracts and pricing mechanisms. Their implications for South Asia will be explained in later sections, but this brief overview will be essential to understanding natural gas trading hubs and why they will be important for South Asia. (3)

Traditionally, as a result of the heavy infrastructure and financial commitments required for natural gas project development, natural gas contracts were of a long-term nature. This can be more clearly understood through Stern's idea of "crisis of fundamentals." (4) He presents a distinction between "economic fundamentals"--referring to "the cost of developing and delivering domestic or imported gas to end-users"--and "market fundamentals," defined as "the price of gas, compared with the price of market substitutes. (5) This reflected the idea of "price risk," that the determined price would commensurate for the investment by the seller, and the "volume risk" that the buyer would be able to sustain a natural gas market large enough for the commitments in the contract. (6)

In some contracts, price review or price re-opener clauses aim to minimize price risk, which allows the price to be revisited through future negotiations. Similarly, the volume risk is diminished by the "take or pay" clauses, an almost ubiquitous feature of long-term contracts that subjects the buyer to penalties if they do not take the agreed quantity of gas. It is interesting to note that long-term contracts in South Asia, such as the Iran-Pakistan agreement, the Turkmenistan-Pakistan-Afghanistan-India (TAPI) agreement, and even India's LNG deal with Qatar's Rasgas have all featured the "take or pay" clause. (7) The implications of this and other liabilities are discussed in later sections. Much of the details of these contracts remain hidden from the public eye because of commercial confidentiality. Sellers of natural gas included upstream gas developers and their affiliates or gas aggregators, and more recently, trading companies for the LNG spot market. [1],(8) In new natural gas markets, long-term contracts started and stimulated the growth of the new gas industry, especially the LNG industry, which required heavier investments. (9)

With the evolution of the LNG spot market, the natural gas market has become more competitive and reduced the need for collaterals. The majority of contracts in the Asia-Pacific region continue to be linked to oil, particularly the Japan Crude Cocktail and Brent oil price indices. Both are popular choices for sellers, but a truly in-depth discussion of every pricing mechanism is outside the scope of this paper. Regional gas prices have seen a far greater spread than oil prices, a phenomenon clearly visible in Figure 2, which shows natural gas prices from 1996 to 2014.

Until 2009, natural gas price trends were similar. At that time, the shale gas revolution brought down U.S. natural gas prices significantly, while demand in Japan increased post-Fukushima. The demand for nuclear energy has fallen since then, yet LNG prices remained indexed to the "Japan Crude Cocktail" (JCC), an oil index connoting the average price of Japan's crude oil imports. (10) The average price that Japan paid for its natural gas imports reached $16.75 per MMBtu, which stands in sharp contrast to the lowest price of the Henry Hub in 2012, which was $2.76 per MMBtu. Thus in 2012, Japan paid on average 84 percent more for the same unit of gas. Once oil prices started tumbling in 2014, production of shale oil and gas slowed. Pressure on the global supply side, among other factors, brought LNG spot prices up from 2012 prices. Japan, as the world's largest importer of LNG, buys from a diverse mix of exporters, including Australia, Qatar and Malaysia. (11) It remains bound to its old oil-indexed long-term contracts...