Energy Trading {unit 07}

CHAPTER 7 GAS TRADING Natural Gas Market in India Natural gas, earlier considered as just a by-product of crude oil production, has now gained significant importance as a valuable source of energy internationally. Natural gas is now gaining prominence as the fuel of the future as it meets clean fuel requirements and is cost effective for major industries, as compared to traditional fuels such as coal and naphtha. Gas assets in India did not receive much attention till few years back. However, mounting oil bills and need for cleaner fuels has necessitated the country to explore its gas potential. Supply deficit has long been a significant feature of India’s gas market. However, year 2004-05 could well become a turning point as these constraints are now loosening up due to LNG (liquefied natural gas) imports and domestic gas finds. Gas market in India Natural gas industry in India is under government control today due to its strategic importance. Till few years back, the production of natural gas in the country was totally under the control of two PSUs viz. Oil and Natural Gas Corporation (ONGC) and Oil India Ltd. (OIL). However, with the New Exploration and Licensing Policy (NELP), private players have been allowed to participate in exploration and production of natural gas. Currently, the two PSUs still account for 83 percent of domestic gas production. Marketing of gas and pipeline infrastructure is undertaken by GAIL India Ltd. Companies such as Gujarat Gas Company Ltd. (GGCL), Mahanagar Gas Ltd. (MGL) and Indraprastha Gas Ltd. (IGL) are engaged in distribution of gas and are regional players. Power and fertilizers are the two primary sectors which together account for close to 80 percent of the gas consumption. Besides, other sectors such as petrochemicals, sponge iron and transportation also consume natural gas. Demand for natural gas in India for 2003-04 was estimated at 98 mmscmd (million standard cubic metres per day). Against this demand, allocations made by Ministry of Petroleum and Natural Gas (MoPNG) stood at around 120 mmscmd. Currently, in India, natural gas forms 8 percent of the primary energy consumption as compared to 24 percent worldwide. According to India Hydrocarbon Vision 2025 report, demand for natural gas is expected to show a sharp rise in the future with the demand reaching to 391 mmscmd by 2024-25. The report also expects that the share of natural gas in total energy mix

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to go upto 20 percent. The demand for natural gas is expected to grow at a CAGR of more than 7 percent by 2007-08. The major force behind this demand growth will be investments in power sector. Government is planning to add power generation capacity of 41,110 MW under the Tenth Plan and over 60,000 MW in the Eleventh Plan. Fertilizer sector will fuel this demand further as major players switch from naphtha to gas as feedstock. Indian market is looking for LNG from suppliers with softer terms and conditions some of which are mentioned below:


Shorter duration contracts




Pricing formula




Fixed price




Quasi fixed Price by setting a formula




Price with Floor and Ceiling




Negotiated ratio of fixed elements while lowering the ratio of the crude oil-linked portion.




Flexible Terms and conditions

This rapidly growing energy market may evolve New Risk Distribution Model. The importers not only will demand that the suppliers bear some of the risks they have taken, but also that they may seek new profits in return for the additional risks they are going to assume by enrolling themselves into entire LNG chain. Indian importers shall endeavor to create an optimal portfolio of LNG contracts by negotiating different pricing formula with different contractual terms. This will enable them to match demand patterns, customer needs and lower generating costs. Natural Gas Trade Given the distances between gas reserves and gas markets, as natural gas reserves are concentrated in a few geographical areas of the world, there is a need to transport natural gas over long distances, across oceans and country borders. Natural gas can be transported in pipelines or as LNG. As natural gas is inherently bulky, it cannot be economically transported in its gaseous form by pipeline across deep oceans over long distances (over 2,500 km), even where long distance transportation is technically feasible. Once liquefied, however, natural gas is much more

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compact, occupying 1/600th of its gaseous volume. This makes LNG convenient and safe to handle, transport and store in large amounts as energy in liquid form. With steady growth in demand, world trade in natural gas has also increased at a CAGR of about 8% over the past 28 years. Between 2001 and 2002, both pipeline exports and LNG exports grew by 4.9%. Projected increases in consumption will require bringing new gas resources to the market. Numerous international pipelines are either planned or are already under construction. The development of liquefaction technology, the need to transport natural gas over long distances across oceans, coupled with cost decreases throughout the LNG chain, has made LNG more economical, and led to expectations of strong growth in international LNG trade. The economics of transporting natural gas to demand centers currently depend on the market price, and the pricing of natural gas is not as straightforward as the pricing of oil. More than 50% of the world's oil consumption is traded internationally, whereas natural gas markets tend to be more regional in nature, and prices can vary considerably from country to country. In Asia and Europe, for example, LNG markets are strongly influenced by oil and oil product markets rather than by natural gas prices. As the use and trade of natural gas continues to grow, it is expected that pricing mechanisms will continue to evolve, facilitating international trade and paving the way for a natural gas market LNG Trade International trade in LNG, which began in 1954, has grown to 150 bcm in 2002. This accounts for around 26% of the total trade of natural gas internationally; the balance natural gas is traded via pipelines. Asia Pacific accounted for about 70% of total LNG imports in 2002 followed by Europe and North America. Japan and South Korea are the key markets for LNG, where natural gas cannot be supplied through pipelines. Japan is the largest importer of LNG in the world, and accounted for 48.5% of total LNG imports in 2002. LNG imports in most countries are backed by the Government or state-owned entities, like Kogas in South Korea, China Petroleum Corp in Taiwan, and Gaz de France in France. In Japan, the importing agencies are power utilities for captive use of natural gas, and gas utilities for distribution. The major exporters of LNG currently are Indonesia, Algeria, Malaysia and Qatar. LNG project developers typically seek a long term contract (20-25 years) for their product at a price that is sufficient to cover their capital costs, which includes take-or-pay and floor price arrangements to ensure that the project can service its debts even in a lower than- anticipated

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price scenario. It is also common for consumers to take an equity stake in LNG projects, so as to have a community of interest between the buyer and the seller. A successful LNG Project must have large and sufficient proven at the end of the project. Indian Scenario India is the third largest consumer of natural gas in Asia, relying until now on domestic production, gas still accounts for less than 10% of primary energy consumption, and the economy is increasingly starved for natural gas and power. For a number of reasons, ranging from environmental concerns to competitiveness in power generation, natural gas remains a sought-after power generation based on imported naphtha and condensates will not be able to compete with natural gas, although increased domestic production could affect demand for gas imports. For now, gas imports via pipeline and increased domestic naphtha production remain more distant possibilities; meanwhile both the government and private industry are pursuing LNG imports. There are plans for several LNG projects at various stages of materialization, and many plans are still changing. Nevertheless, the earliest projects of Petronet LNG and Royal Dutch Shell would be in operation by 2004/2005. Meanwhile, there are several obstacles, and sources of potential delay in meeting targets, that confront LNG projects, such as the need to secure natural gas suppliers and consumers, ensure sufficient prices and confirm the market's ability to pay. India as an LNG importer will differ significantly from existing Asian buyers in the East (Japan, South Korea and Taiwan). India population, but has a much lower per capital income. It produces some domestic oil and gas (although potentially under-explored), and has some existing pipeline infrastructure. India's large agricultural sector means that the fertilizer industry (and petro-chemicals in general) will facilitate increasing use of natural gas in the domestic economy. While China could conceivably also benefit from a strong fertilizer industry, its pipeline infrastructure is less developed, and what does exist may not be as helpful as India's major gas pipeline running inland from the Western coast with several spurs. Still, like much of Asia, neither China nor India currently has extensive gas infrastructure for supplying residential or commercial users, or even a wider variety of industrial users across the length and breadth of these two very large countries. Like Asia, India's primary energy mix is dominated by coal, owing to coal's availability in abundance at a lower cost, relative to the other energy sources. While primary energy consumption grew by 3.5% in 2002, coal marginally increased its share in the energy mix from 54.9% in 2001 to 55.6% in 2002, and oil lost share marginally from 30.8% to 30%. Natural gas maintained its share at

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7.8%. Going forward, as per estimates, the total share of oil and gas in the primary energy mix is not expected to change substantially. However, gas, owing to its non-polluting nature and ease of use as compared to oil, is expected to gain significance and have a greater share in the primary energy mix. Demand Of gas The increasing importance of natural gas, as a fuel and as a feedstock, is expected to drive the demand for natural gas in India. With gas' share in the primary energy mix projected to increase to 15% by 2007 according to the Hydrocarbons Vision 2025 report, the demand for natural gas is projected to increase from 151 mmscmd in 2002 to 231 mmscmd in 2007 and 391 mmscmd in 2025. In 1991, GoI established the Gas Linkage Committee to re-assess the potential of gas production and establish the priority of gas availability of gas. Based on the recommendation of the Committee, MoPNG makes the gas allocations. Natural gas is used in India as a fuel in power plants using combined-cycle technology, and as a feedstock in the fertilizer and petrochemical industries. It is also used as a fuel in several other industries, such as glass, ceramics, sponge iron and tea. Supply of gas It increased more than ten-fold (from 2.4 bcm in FY1981 to 31.4 bcm in FY2003) after the Bombay High field commenced production. Initially, the demand for gas was low, but with commissioning of the HBJ pipeline and projects, demand rapidly increased. Currently, there is a shortage of gas, and this demand-supply gap is projected to increase with strong growth in demand vis-à-vis plans to bridge this gap by resorting to alternate sources of gas. This strategic importance of natural gas for the Indian economy coupled with a shortage of supply and its recognition by the GoI has had an impact on the evolution of the fiscal and regulatory environment for natural gas . Analysis of Natural Gas Demand & Availability from Various Sources Currently most of India’s gas is produced from the western offshore fields which include South Bassein fields, Joint Venture fields of Tapti & Panna-Mukta and production of Associated Natural Gas from Mumbai High. The gas supplies from South Bassein fields and JV fields are fed into HBJ system for gas supply to Northern and North-western part of India including Gujarat. The other onshore gas producing regions within the country are as follows:

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•

Cambay Basin, Gujarat

•

Cauvery Basin

•

Krishna-Godavari Basin

•

North-Eastern region including Assam & Tripura

•

Rajasthan

Natural gas availability After deducting internal use of natural gas by gas producers, the average supply of natural gas from various sources to customers is as follows: Producer

(MMscmd)

ONGC

51

OIL

4

PMT JV consortium

10

Cairn Consortium

3.5

Other Private

3.5

Total

72

Around 18 MMSCMD of RLNG is being supplied over and above 72 MMSCMD, making the total availability of gas in the country to the extent of around 90 MMSCMD. Further, DGH have projected natural gas availability in medium to long term. As per the projections made the current domestic availability of natural gas is likely to increase to around 152 MMSCMD in 2007-08 due to upcoming of various new sources such as RIL, Kochi LNG etc. However this availability is likely to decrease to around 130 MMSCMD in 2010-11 due to decline in gas availability from current largest domestic gas source i.e ONGC. It may be seen that the domestic gas availability from ONGC shall be decreasing from 53 MMSCMD in 2006-07 to around 30 MMSCMD by 2010-11. In order to bridge the growing deficit between gas demand and availability, GAIL is trying to import natural gas either in the form of LNG or through transnational pipelines. The likely availability of natural gas from these sources is as follows:

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(MMSCMD) Source

Quantity

Likely start Year

18

4th Qtr. 2009

Iran, LNG Iran P/L

60 – 120

Myanmar

28

-

8 – 18

-

ADGAS/Petronas/

Qatar/Australia

Total

2010

114 – 184

Since the gas availability from international sources is long term in nature, therefore it is envisaged that the total gas availability in the country by 2010-11 could be in the range of 244-314 MMSCMD. Summary of Gas Availability (MMscmd) : Source

Immediate

Medium Term

Long Term

(2007-09)

(2010-2011)

ONGC

51

50

30

OIL ( Raj.+NE)

4

5

5

Sub Total

55

55

35

JV producers

17

53

59

LNG sources

18

30

36

Iran LNG

--

--

18

Transnational pipelines* : Iran and Myanmar

--

--

148

Other LNG sources*: Adgas, Petronas, Qatar. Australia

--

--

18

90

138

314

Total Source: DGH/OIL/LTGP 2K * Expected

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Gas Demand The power and fertilizer sectors have been core consumers of natural gas. These two sectors together consume about 70% of the gas today. The balance goes to industrial units where it replaces mostly liquid fuels. Gas is also supplied to the residential and the commercial sectors in Mumbai, Delhi and a few towns of Gujarat, Assam and Tripura. Over the past many years a number of gas demand projections have been made by various agencies.

Projections A number of attempts have been made so far to estimate the future demand for gas. Although the figures do change every time the exercise is taken up, a trend of increasing demand far exceeding the supplies available from indigenous sources seems to have been well established. In a meeting taken by Secretary (P&NG) on 29.04.2005 regarding projected demand of natural gas in medium to long term. The meeting was attended by officials from Ministries of respective consumer industries viz. Power, Fertilizer, Steel, etc. and experts from other companies/agencies involved in gas business. The demand of natural gas as assessed is provided below: Immediate/Medium term requirement (say 2007-08) (MMSCMD) Sector

Shortfall

Conversion

Additional

Total

11.19

12.99

-

24.18

Power

18

-

21.42

39.42

Steel

3

-

3

Industrial*

12.69

12.69

City gas*

6.81

6.81

40.92

86.1

Fertilizer

Total

32.19

12.99

* Note: It is assumed that the immediate/Medium term requirement for Industrial and City gas sector shall be 50% of the total projected demand of gas, as assessed by MoP&NG, for the industrial & city gas distribution projects i.e 25.37 & 13.61 MMSCMD respectively in 2009-10.

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The above gas demand was considered in addition to the existing gas supply of around 99 MMSCMD to various sectors in the country. Therefore, it was estimated that the total gas demand in the country in the immediate/Medium term requirement could be 185.1 MMSCMD, i.e. around 185 MMSCMD. However, it was also considered that the demand could be lower if the delivered price of natural gas is increased from $ 3.0 MMBTU to $5.0 MMBTU. Long term requirement (say 2010-11) (MMSCMD) Sector

Shortfall

Conversion

Additional

Total

11.19

22.41

-

33.6

Power

18

6

124.42

148.42

Steel

3

4

7

Industrial

25.37

25.37

City gas

13.61

13.61

167.4

228

Fertilizer

Total

32.19

28.41

Thus, the total gas demand in the country in the long term could be 327 MMSCMD (i.e. current supply of 99 MMSCM plus new demand of 228 MMSCMD). Estimated Demand at US$ 4.0/ MMBTU (MMSCMD) Sector

2005-06

2008-09

2011-12

Power

85.68

159.55

182.11

Fertilizer

43.76

57.18

61.98

Industrial

45.17

52.87

61.8

Domestic + Commercial + Automobile

5.66

7.43

9.92

180.26

277.03

315.81

Total

However, the demand of natural gas goes down significantly if the price of natural gas/RLNG is increased by $1/MMBTU. The demand of natural gas , as assessed by independent agency (MDRA) @ price of $5.0/MMBTU is as follows:

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Estimated Demand at US$ 5.0/MMBTU (MMSCMD) Sector

2005-06

2008-09

2011-12

Power

0

0

0

Fertilizer

0

0

0

Industrial

45.17

52.87

61.8

Domestic + Commercial + Automobile

5.66

7.43

9.92

50.83

60.3

71.72

Total

Total domestic production of natural gas is to the extent of around 72 MMSCMD. Further around RLNG to extent of around 18 MMSCMD is available from PLL-Dahej and Shell-Hazira. Further, current domestic availability of natural gas from largest domestic source i.e ONGC is projected to decrease from 53 MMSCMD to around 30 MMSCMD by 2010-11. This shall be offset from increase in domestic availability from private gas sources such as RIL and other NELP fields. Import of natural gas in the form of LNG and through transnational pipelines would be major sources of gas availability. Taking all the above into account, the total gas availability in the country shall increase to around 244 - 314 MMSCMD by 2010-11. As against the total gas availability of around 244 - 314 MMSCMD by 2010-11, the total projected demand of natural gas will be 327 MMSCMD by 2010-11. However, In the medium term i.e. 2007-08 it is estimated that as against the total demand of around 185 MMSCMD, the gas availability in the country shall be only around 152 MMSCMD Gas Trading Natural gas trading refers to the resale of natural gas in the wholesale market, and supply to resale in the retail market. (In the United States gas trading and independent gas supply are considered part of marketing.) Because these two operations are closely related, they are often performed by the same firm. The gas trading and supply business is a very competitive segment because of the limited scale economies. Traders and suppliers need little up-front investment to start operations— a trader needs

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only a desk, a computer, and a telephone to contact customers and make deals. As a result, the optimal size of a gas trader or supplier is small relative to the gas market. This optimal size increases with deregulation of the industry— because markets become more complex, with increasing use of short-term and financial transactions— but not enough to pose a threat to competition in the segment. Role of Gas Trading

Supply Demand Matching The uncertainty of demand Long-term contracts will only be signed if there is a secure potential for an outlet. The fact that the national markets are immature with weak internal infrastructures, means that most potential outlets in the new markets (about 85%) are in the fields of electricity production, chemical usage and some other big consuming sectors. This fact alone restricts the potential for development, and as a result the import projects are mostly linked to electricity production projects; this is a well-known pattern already encountered in previous market developments in Japan and South Korea. It will be favored in future because of the liberalization of the electricity industry and the advent of independent power producers using combined cycle gas turbine equipment. In future, however, it will also be severely restricted by the level of networks and urban distribution networks, as will be the case in China and India. Expanding spot trading contributes to increasing flexibility of supply Spot trading of LNG, which is a yardstick of flexibility, is increasing at a rapid rate. Transactions under short-term contracts (less than a year and inclusive of spot trading) in 2001 recorded a tenfold increase over 1992 levels and reached a hefty 8% of total trade (IEA, “Flexibility in Natural Gas Supply and Demand”). Above all, conspicuous rises were noted in spottraded LNG destined for the US. In order to expand their LNG sales, the oil majors, among others, are no longer remaining idle in the position of investors, interest holders and/or suppliers of LNG in the upstream sector. They are adopting the strategy of becoming LNG buyers themselves and are collecting the surplus capacities of many projects, while tapping new demand. The colossal U.S. market (consuming ten times more natural gas than Japan) can easily digest such moves. This is why the US-bound LNG spot trading is ballooning so rapidly. This concept is becoming real in the Atlantic

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market, as demonstrated by expanding spot transactions. In the Asia/Pacific market too, introduction of a similar strategy is under consideration. LNG terminal construction projects and commercialization of on-board gasification technology on the U.S. West Coast, among others, all point to this concept. Expanding spot trading is beneficial to both suppliers and consumers, since it enables the former to put their surplus capacities fully in operation . Price Discovery Lack of transparent pricing mechanism The factor behind under-utilization of natural gas in Asia is the lack of transparent and competitive gas pricing mechanisms. Though Asia dominates the growing world LNG trade, LNG accounts for only a quarter of international gas trade, and involves only a few countries in Asia. For most Asian countries, natural gas is locally produced and consumed. Unlike the oil market, there is no international gas market to which Asian countries can link heir domestic natural gas prices. In some with the prices of fuel oil. In other countries, including China and India, natural gas prices are determined and regulated by the governments, often set at low levels to benefit industrial sectors, or to subsidize the residential sector in areas adjacent to natural gas fields. Excessive government intervention in natural gas pricing has discouraged exploration, development and production of natural gas in many Asian countries, lading to lower natural gas consumption. These four factors, combined, have contributed to a low level of gas consumption in Asia. Promoting gas consumption did not become a priority for Asian governments until the economic boom of the 1980s generated the skyrocketing energy needs of the 1990s. Prices Fluctuate


Changes in gas cost – major factor




Seasonality in demand




Product supply/demand imbalances




Proximity of supply/supply disruptions




Competition in local market




Environmental regulatory programs




Costs to produce cleaner products

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Consideration of pricing -formula options Options of future “pricing formula” are summarized below.


Fixed pricing (stated by a PETRONAS vice president for gas at SPEC 2002; oriented toward a crude oil price-free mechanism)




Quasi- fixed pricing by setting a small figure for “a” in the formula, P = aX + b




(adopted by China/India; oriented toward lower price and stability)




Raising the ratio of fixed elements while lowering the ratio of the crude oil-linked




portion (proposed by a Japanese importer at the World Gas Congress 2000; oriented toward lower price and stability)




The retail price of coal/coal- heavy fuel oil-crude oil/electricity, etc. taken as price




indicators (prevailing on the European Continent; to help LNG-fired power retain/stabilize its competitiveness against rival power sources)




Petroleum products such as heavy fuel oil and kerosene taken as price indicators




(prevailing on the European Continent; to help LNG-derived city gas retain/stabilize its competitiveness against rival fuels)




LNG pricing linked to NYMEX/IPE futures (in order to reflect on-going market




conditions)

Making the contract two-tiered, with a flexible delivery portion (to better meet seasonal demand) and a fixed delivery portion (separation of price and flexibility) Many options of pricing formula will be available in the future. It is also possible to arrange a wide variety of LNG contracts by pairing different pricing formulas with various trading patterns, each having flexibility of its own (e.g. long, medium and short contract terms, varying TOP coverage, non-uniform deliveries). Trading Models in the Deregulated Natural Gas Industry Trading mechanisms guide transactions in natural gas and transportation markets. They facilitate interactions among market participants with the objective of achieving simultaneous clearing of natural gas and transportation markets at minimum cost to the gas industry. Deregulation of the natural gas industry leads to separate trading of natural gas and transportation services, which increases the complexity of markets and imposes substantial requirements on market participants if they are to complete all their transactions at the minimum cost. While a vertically integrated gas company

215

optimizes all transactions internally, participants in a deregulated gas industry must coordinate their natural gas and transportation transactions in an open market. The process of minimizing the total cost of natural gas and transportation to the industry must take place across thousands of decentralized transactions. Unless these transactions are guided by a trading model, they can result in sub optimal allocation of resources. Bilateral trading model The bilateral trading model is based on decentralized bilateral transactions. The model relies on competitive gas and transportation markets to generate efficient prices and minimize the cost of natural gas to the end users.

Decentralized spot markets In the bilateral trading model market participants conclude all deals in bilateral negotiations and write contracts that address all issues relevant to a transaction. Demand for ways to minimize of transaction costs leads to the emergence of traders who complete transactions on behalf of other market participants. Spot markets develop as market participants require efficient pricing of natural gas at every moment. Spot markets are thus developed through the decentralized action of market forces. Competitive spot markets generate signals about the market value of natural gas and give market participants the right incentives to complete transactions efficiently. As a result, decentralized bilateral trading among market participants achieves the outcome that is optimal for individual participants as well as for the natural gas industry as a whole.

Distance-based pricing of transportation Charges for transportation services sold in the primary transportation market are based on the fixed and variable costs of a pipeline company per unit of distance over which individual shipments take place. A capacity charge is set to recover total fixed costs, while a throughput charge is used to recover the variable costs of transporting natural gas. Transportation contracts sold in the secondary market are priced according to the short-run marginal cost of capacity. A competitive secondary capacity market and the availability of many different firm and interruptible transportation contracts enable shippers to match their needs for natural gas with transportation

216

services. They form a portfolio of transportation contracts that gives them the minimum acceptable reliability of transportation at the minimum cost. Because each shipper is able to minimize its total cost of natural gas and transportation, the total cost of natural gas to end users is minimized. The Models are shown as : Model 1 has a nonexistent wholesale market because all natural gas transactions are conducted internally by a single vertically integrated company that also monopolizes the retail market. The monopoly in market leads to the increase in the prices of gas. Model 2 has limited competition in both the wholesale and the retail markets. Prices of natural gas in models 1 and 2 are regulated to prevent excessive pricing by the dominant gas utilities. Models 3 and 4 have relatively competitive natural gas markets, and model 4 has a more competitive transportation market than model 3.

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218

219

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NATURAL GAS TRADING AND FUTURES MARKETS INTRODUCTION A look at natural gas commerce in North America at the dawn of the 21st century reveals an extraordinarily competitive, robust business, one that has become the commercial model for gas industries throughout the world. Gas supplies are traded in spot markets alongside longterm contracts, and capacity in pipelines and storage caverns is likewise traded on a commodity basis. Electronic markets (screen trading) and price risk management tools are widely used. All this is taking place in a climate of ample supplies and growing demand. It was not always this way. Until the mid 1980s, natural gas was a rather invisible, staid, utility-like business operating under heavy-handed economic regulation. This chapter traces the growth of open trading (commoditization) of natural gas in North America, which led to one of the most successful new futures contracts in the history of commodity markets. It then characterizes the way gas markets worked as of the turn of the century, including spot and long-term contracting, gas futures and derivatives, and trading of transportation and storage capacity. A final section then projects where key trading and futures developments appear to be leading the North American gas industry.

BACKGROUND Natural gas is distributed to 56 million households and businesses in the U.S. and Canada and has, for the past three decades, provided about one out of four units of energy consumed. Once delivered into any major gas pipeline system, natural gas is a completely fungible commodity composed chiefly of methane, with trace amounts of propane, carbon dioxide, and other gases. Natural gas in pipelines is virtually free of sulfur and is odorless; that common odor of natural gas is actually mercaptan-a substance injected for identification (safety) purposes. Gas is produced in 25 states and six provinces of the U.S. and Canada, respectively, including onshore and offshore producing fields. Most gas used in North America (75%) is produced from gas wells-the remainder is produced in association with oil. The continent is largely self-sufficient in natural gas, with relatively small amounts of liquefied natural gas (LNG) imported into the U.S. East Coast,

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approximately offset by amounts of LNG exported from Alaska to Japan. Most North American gas is produced on and off the Texas-Louisiana Gulf Coast and the mid-continent regions, with major rising production in Alberta, British Columbia and the U.S. Rocky Mountain states. Substantial gas production takes place in Mexico as well. To a lesser extent, gas is also produced in Appalachia, Mobile Bay, California, and offshore eastern Canada. In 1982-following 35 years of commodity price regulation-the U.S. gas industry began to completely change the way it bought and sold gas. From the Phillips decision in 1954 through the initial gas shortages in the 1970s, price controls on interstate gas seemed to succeed in ensuring adequate supplies of low-priced gas to customers and maintaining the pre-existing commercial structure of the business. That is: gas was sold by producers under long-term contracts primarily to regulated pipeline companies and then to regulated local utilities for distribution to final consumers. However, massive shortages of interstate natural gas in the 1970s-culminating in the temporary unemployment of more than one million people in the winter of 1977-resulted in passage of the Natural Gas Policy Act of 1978 (NGPA). The NGPA raised gas prices and set them on a gradual course toward deregulation. Indeed, natural gas was never actually in short supply in the U.S., but pricecontrolled gas was? From the enactment of the NGPA through 1982, the gas industry resumed its long-term contracting practices in a period of intense exploration and development efforts, buoyed by high and seemingly ever-rising oil prices. The decline in proven gas reserves that had worried so many policy makers in the 1970s was immediately arrested. After 1982, however, oil prices slipped amid a sluggish economy, and competitive forces became irresistible. The Federal Energy Regulatory Commission (FERC) promulgated a set of rules that turned gas pipelines primarily into transporters of gas on behalf of shippers. GAS SPOT AND TERM MARKETS

North American gas markets are segmented into immediateterm, spot, medium-, and long-term contracts. For convenience, these may be thought of as spot and term markets, the former consisting of arrangements of one month or less in duration, and the latter consisting of arrangements of all longer terms (e.g., three months, one year, or up to 15 years). Spot markets-where unimpeded by government-exist to reconcile immediate imbalances in supply

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and demand for a commodity. Spot gas markets evolved in the U.S. and Canada throughout the 1980s and 1990s in increasingly fluid trading environments. Throughout the North American gas industry, reported spot gas prices have become the gas industry's standard reference for gauging fair market value. By 1998, four of every five units of natural gas were traded in contracts of one year or less, with some 40% of one month or less. Typical spot gas arrangements involve flows of a day or two to 30 days, with separate procurement of pipeline capacity in equally short-term markets. Such transportation arrangements consist of interruptible services on a best efforts basis from a pipeline and/or LDC, released capacity, short-term firm transportation arrangements directly with pipelines, or pipeline "no-notice" transportation arrangements. Gas and transportation trading now commonly takes place throughout the industry at every major level, including even the residential market in some localities. Buyers of spot gas include gas trading (marketing) companies, gas distributors, electric utilities, most major manufacturing industries, and numerous commercial establishments. Sellers include gas marketing companies, most major and independent gas producers, processors, and utilities.

As comfort with gas spot trading increased during the 1980s, the spot market provided a foundation for resurgence of long-term gas contracts (often referred to as "term" contracts). JYpically, industrial users, electric utilities, and gas utilities enter into term contracts to purchase gas for a season, a year, and two to three years. Term contracts rely on spot markets in several ways. For example, they draw their price signals from the spot market through their use of price indexation, they presume the spot market will be there when the parties terminate, and they may often use the spot market as an alternative channel. In particular, pricing provisions in term contracts are written with reference to prices reflective of gas spot markets (e.g., Henry Hub NYMEX futures or spot gas plus or minus a locational basis--explained below-as well as averages of indices reported in trade press, spot price reports at several pipeline inlets, and more). Where customers must borrow or spend substantial sums on gas-consuming equipment, still longer-term gas contracts are often an essential, and sometimes a required, commercial mechanism (e.g., to support debt financing of independent power projects).

THE GAS MARKETING SERVICES INDUSTRY

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A new, fourth segment of the gas industry has emerged and is here to stay-the gas marketers. The role of these players is to lend flexibility and fluidity to gas marketing transactions at all levels. More than 300 independent and affiliated natural gas marketing companies evolved in the 1980s to conduct gas trading, including buying and selling gas, trading pipeline capacity, arranging transportation through gas distributors, and otherwise facilitating markets. By 2000, the numbers had not changed greatly but the composition changed, with more marketers involved in a wide variety of additional trading activities, including electricity, power generating capacity, financial risk management and local residential and commercial gas services. Overall, marketing natural gas has by itself grown into a multibillion dollar business including earnings. Early on, traditional players in the gas business (i.e., in the three preexisting segments of the industry-producers, pipelines, and LDCs) formed gas marketing subsidiaries to capture newly recognized profit opportunities and often simply to facilitate gas transportation. The FERC responded by issuing rules and otherwise acting to prevent pipeline-affiliated gas marketers to secure market advantages. With the advent of gas futures trading in 1990, the gas marketing industry grew intensely competitive, with many financial services companies becoming involved in gas marketing. By the late 1990s, as understanding of the benefits of this industry grew, more firms from different industries entered the business, including independent power generators, fuel oil distributors, merchandising and retail firms, and more.

TRANSPORTATION CAPACITY TRADING AND "BASIS" Trading of pipeline and storage capacity takes place in primary and secondary markets, although the two mechanisms are economically intertwined and often indistinguishable. Primary capacity markets consist of a set of contracts, typically either firm or interruptible, between the physical pipeline and storage asset owners and gas shippers. Secondary markets consist of arrangements among shippers for "parcels" of firm transportation, including short- and long-term releases. As the gas spot trade grew in the 1980s and early 1990s, pipeline capacity arrangements for shipping spot and other direct market gas were made entirely in primary markets, i.e., firm and interruptible transportation contracts directly to shippers. By the late 1990s, secondary capacity markets had grown in importance to at least equal primary markets, with capacity release as the major trading instrument. Indeed, primary and secondary transportation markets have melded into a fairly

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competitive commodity trade in pipeline capacity, whose currency (i.e., the price variable) is referred to as "basis." Basis competition dominates markets for gas pipeline capacity. The basis differential (or simply basis) is defined as the difference in the value of gas, the commodity, at one location vs. another location. As competitive pipeline capacity markets gained in trading activity, competitive basis differentials emerged among dozens of market centers, or hubs, throughout North America. Basis need not equate to cost-ofservice transportation rates on pipelines. Instead, basis is determined by supplydemand balances in different markets and, as a consequence, constitutes a valid measure of the value that markets place on pipeline capacity at any point in time.! If points A and B both represent active gas hubs, then the basis difference is the most (or the least) that markets will pay for pipeline transportation between A and B on a spot basis. For example, if the cost of spot gas at A and at B is $2.00/Mcf and $2.15/Mcf, respectively, then the basis differential is $.15/Mcf. Thus, pursuing this example, if we assume that the pipeline's maximum transportation rate to haul gas from A to B equals $.25/Mcf, then basis in secondary markets works as follows: If basis is less than maximum rates, then releasing shippers typically discount to meet basis:2 Apart from long-term contract arrangements that may be in force, no releasing shipper can reasonably expect to receive on a short-term basis more than to day's basis for shipping gas from A to B today, regardless of its lawful maximum tariff rates. In short-term capacity markets, an attempt to collect maximum rates would at least encounter basis competition: a shipper in our example would sell off the gas at A for $2.00/Mcf, and repurchase gas at B for $2.15/Mcf, calling the loss of $.15/Mcf the cost of "transportation" from A to B. Thus, basis limits the rates releasing shippers can charge over a period of time. If basis exceeds maximum rates, then releasing shippers are limited to charging below market rates for transportation services: Likewise, if basis reaches $.40/Mcf in our example, marketers will "receive" the full $.40 to "transport" gas from A to B, even while the pipeline collects only its maximum rate of $.25/Mcf under current regulation. A marketer's price of gas at B would reflect the basis difference, with any mark-up included in the gas commodity cost as a bundled add-on.3 Note that markets at A and B are assumed to be competitive, i.e., they are reflective of the instant supply-demand balance at each point. Thus, it may be said that the market is capping at $.40/Mcf, the transportation "rate" that a

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shipper would need to pay for capacity from A to B, in this example. It is clear from the foregoing that, at any given time, competitive basis relationships may have little to do with pipeline's cost-of-service rates, but instead, they relate more directly to the nexus of supply and demand at each hub or market center.

MARKET MECHANISMS The North American gas business has evolved and solidified a monthly spot market bidding system that has become a normal, institutionalized part of the industry's commerce. The mechanisms described below are intended only as an approximate guide to the basic flows of information and will differ from marketer to marketer, customer to customer, pipeline to pipeline, jurisdiction to jurisdiction. In summary, the process regularly works as follows for thousands of gas market participants: •

Toward the end of each month (bid week), gas marketers and others complete commercial arrangements for gas supplies in the next month. Such arrangements are not limited to bid week, and may take place throughout the month via phone, fax, the Internet, and/or pipelinebased and other electronic bulletin boards.

•

Within approximately a week before the end of each month, those planning to physically transport gas on pipelines (known as shippers) make or confirm their transportation arrangements either directly from pipelines' transportation departments or in secondary markets by bidding for and obtaining released pipeline capacity.

•

As required by their capacity arrangements, shippers then submit nominations for daily transportation capacity to pipelines over the next month, identifying expected daily gas volumes, receipt and delivery points, and other key information.

•

Over the next hours or day, pipeline capacity reconciliation staff review nominations and provide feedback to shippers as to capacity limitations, bottlenecks, and/or similar issues.

•

Financial risk management steps are taken at this time, including completion of hedge arrangements, EFPs and other transactions. As required, credit and related information is provided among parties to transactions, both commodity and transportation.

As the month ends, the business enters a clean up phase, in which the final deals are completed for

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the new month and final transportation arrangements are made-hurriedly at times. At this point, any final changes to transportation pricing are also agreed upon to the extent warranted by capacity and competition. Throughout the month, trade publications report gas prices at some three-dozen geographical points on a daily and weekly basis. Increasingly, the business is also relying on the Internet, pipelinebased and other electronic bulletin boards, instant price reports, and the like. As information systems improve, the above process will continue to streamline in several respects, including shorter capacity bidding periods, faster cycling of customer demand information (e.g., for power generation and industrial uses), and improved price reporting and averaging (e.g., on-screen changes throughout the day).

Financial gas market The financial gas market is the market place where financial gas contracts are traded. A financial gas contract is used primarily for managing price risk and is not necessarily for physical delivery. Participants in the financial gas market come from all segments of the gas industry. Because transactions in this market involve the transfer of risks among these participants, intermediation plays an important role. The main intermediaries are traders and financial institutions, such as banks and organized exchanges. Financial gas contracts are highly variable because of the heterogeneity of needs of market participants. The most common types of contract are forward contracts, swaps, futures contracts, and options.

GAS FUTURES TRADING

Following six years of steadily maturing gas spot markets during the 1980s, natural gas futures trading commenced on NYMEX on April 3, 1990. The NYMEX gas contract emerged as one of the Exchange's biggest successes, with open interest nearly two thirds of NYMEX crude oil as of the late 1990s-impressive because natural gas is a North American market, while crude oil is worldwide. In general, futures markets seek to provide three essential functions-price discovery, risk management, and investment opportunity, as follows:

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A futures contract is a represents a legal agreement between a party that opens a position on the futures market to buy or sell natural gas and the commodity exchange. The party agrees to accept or deliver, during a specified month, a certain quantity of natural gas meeting quality and delivery conditions described by the exchange. If delivery takes place, it occurs during the delivery month at a prescribed settlement price. Futures contracts are traded exclusively on regulated exchanges and are settled daily based on their current market value. Future contracts are essentially agreements to buy or sell a given quantity of a particular share for delivery at a specified future date but at a price agreed today. The futures price agreed between the buyer and seller is simply the reference price upon which the future exchange of the underlying instrument is based. Also at the time the trade is initiated, a small payment known, as .initial margin. has to be made at the outset by both buyer as well as seller of the futures contract. Also daily profits and losses are paid between buyer and seller with a final payment made at delivery. For an indexbased contract, the question of final payment of delivery does not arise since all such contracts will be cash settled only. The daily settlement of profits and losses is known as marking to market.


The buyer of a future contract is said to go long the future, whereas the seller is said to go short.




Expiration date is the delivery date or final settlement date in case of index futures.

The price changes of the future will reflect the price changes of the underlying instrument (share or index). With a long position, the value of the position rises as the instrument price rises and it falls as the instrument price falls. With a short position, a loss ensues if the instrument price rises but profits are generated if the instrument price falls. It is possible to crystallize the profit or loss before the expiration period by entering into an equal but opposite transaction with the same expiry date. . Usefulness of Futures The key motivation for futures is that they are useful in reallocating risk either across time or among individuals with different risk bearing capacities e.g. hedgers (who want to reduce risk) and speculators (who want to acquire more risk). It is the interaction between hedgers and speculators that not only provides a mechanism for the transfer of risk but also the rationale for futures market. Futures for speculation:

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As the price moves in tandem to the price of the underlying instrument, a long position in the future contract can be used to speculate on a rise in the price of the underlying instrument. Conversely a short position can be used to speculate on the price of the instrument falling. Futures for hedging: When a short position in a future is combined with a long position in cash market for the underlying instrument, the combined position is said to be hedged .i.e. the risk of changes in value to the combined position is reduced or removed. A financial gas market tends to develop once the physical gas market has reached a certain maturity and most natural gas is traded under short-term contracts. Since few countries have a liquid and mature spot market, the financial gas market is relatively new to the gas industry. Only the United States has a well-developed one. Swaps and forwards are usually among the first financial gas contracts developed. They tend to be customer-specific contracts, developed by financial intermediaries and traders to suit the needs of individual clients— producers, distribution utilities, and large end users seeking to minimize the price risk they face in the physical gas market. Demand for financial gas contracts increases as the physical gas market matures. The concentration of gas trading in spot markets facilitates the development of standardized financial gas contracts, such as futures and options contracts, that are developed and supplied by organized exchanges. For example, The New York Mercantile Exchange (NYMEX) and the Kansas City Board of Trade (KCBOT) in the United States have introduced standardized natural gas futures and options contracts for delivery in four major spot markets in the United States and Canada Financial gas contracts serve two main purposes. They minimize the price risk in the natural gas spot market, and they minimize the basis risk resulting from the imperfect match between physical and financial gas contracts. They also serve as an instrument for speculation and price arbitrage in the gas market. Price discovery. First, well-developed futures markets tend to become preeminent price discovery tools, promoting increased competition in markets. Futures prices are widely disseminated and available to all regardless of whether or not they are involved in futures market trading per se. In particular, NYMEX gas futures prices are carried by The New York Times, The Wall Street Journal,

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more than a dozen gas trade press reports, and most Internet-based commodities reporting services. Since trades in the gas futures market are based on cash commitments, convergence between gas spot and NYMEX Henry Hub futures prices has been excellent (rsquared coefficient of 98.95% in 1997). With this high degree of price exposure and confidence, it is not surprising that Henry Hub gas has become the standard price index for the North American continent, and NYMEX and/or Henry Hub cash prices are commonly found in long-term contracts as the parties' agreed upon index. Price referencing to NYMEX extends to term contracts written for Canada and Mexico as well, each enabled by confidence in continuing market volumes of trade, liquidity, and price transparency of the futures market. Risk management. Trading of commodity futures provides a mechanism to cope with fluctuating prices through the process of hedging, i.e., exchanging uncertain cash flows in physical market transactions with certain cash flows in futures market transactions. Gas marketers are especially prone to hedge on the NYMEX Henry Hub futures market because they experience price risk on both sides of their transactions, i.e., buying and selling gas in physical markets. By taking positions in commodity markets, they effectively lock in prices at known levels, rather than await future price fluctuations. There are two classic types of hedges-the short hedge and the long hedge. An example, In the short hedge, Short Company (ShortCo) owns a volume of natural gas reserves, but fears its value may drop in the future. Therefore, ShortCo decides to protect the value of its reserves by selling a futures contract. For example, suppose that in January, the futures price of natural gas for May delivery is trading at $2.00 per million British thermal units (MMBtu). However, ShortCo believes that by the time May arrives, gas prices will turn out lower than $2.00 per MMBtu. By selling into the futures market, ShortCo has locked in a price of $2.00 per MMBtu. When the end of April arrives, if gas prices have indeed fallen to $1.50 per MMBtu as feared, ShortCo will buy back its futures contract at the market price of $1.50 per MMBtu. It will thus realize a $.50 per MMBtu profit in futures that will offset the decline in the value of its hedged reserves. On the other hand, if May cash prices increased to $2.50IMMBtu, ShortCo will surely lose $.50 per MMBtu in gas futures, but that loss will be offset by the $.50 per MMBtu gain in the value of its gas reserves. The point is that, in either case (whether prices rose or fell), ShortCo accomplished its goal of hedging (or offsetting, or locking in) the value or price of its gas reserves. Note that, to the hedger, it becomes immaterial whether May gas prices turn out to be higher or

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lower than expected, at least insofar as the hedged volumes were concerned. The hedger's goal was to shed risk, as opposed to the goal of the speculator, who is discussed further below. The example of the long hedge works in a parallel but opposite way: LongCo, a manufacturer, has promised to deliver the goods it produces at a fixed price, despite the risk of considerable increases in its production costs with potentially rising gas prices. To protect against the feared increase in gas prices, LongCo buys a gas futures contract and thereby locks in the current price of gas for later delivery. If prices actually rise, LongCo's increase in production costs will be offset by the profit made in selling the gas futures contract back at a higher price than the price for which it was originally bought. Thus, the short and long hedges are simply mirror images of one another, in a financial sense.

Investment opportunity. As the hedger passes on the price risk, someone must be willing to incur it, which brings up the third major function of a futures market-investment opportunity and the role of the speculator. The principal attraction of futures markets to the speculator is the high leverage and accompanying profit potential produced by low margin requirements. Speculators are attracted to volatile markets, where prices fluctuate frequently. Natural gas is no exception. However, unlike the 300 gas marketing companies that physically trade natural gas and hedge to manage price risk, speculators do not generally have a cash market commitment to back their trades; they simply take a position, hoping that the price will move in their favor, leaving them with a profit. The private funds that flow to commodity trading provide the necessary liquidity and a fresh source of risk capital to the natural gas industry.

NYMEX GAS FUTURES CONTRACT

A approved by the Commodity Futures Trading Commission (CFTC) in 1990 and modified throughout the 1990s, the NYMEX Henry Hub gas futures contract contains the following major elements: •

A volume of 10,000 MMBtu delivered ratably over a period of one month in even daily deliveries of approximately 320,000 cubic feet per day

•

Physical deliveries available in Erath, Louisiana, at Texaco Pipeline's Henry Hub, which is the most active spot gas trading point in the U.S. linking most major U.S. gas pipelines in the

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Texas-Louisiana Gulf Coast region with direct or indirect service to every gas market in North America •

Natural gas meeting standard pipeline quality specifications, thus acceptable for transportation on any major pipeline

•

Arrangements for exchanges of futures for physicals (EFP), alternative delivery procedures (ADP), and other options

•

Trading cessation three business days before the end of the month to allow time to complete pipeline transportation arrangements consistent with existing gas pipeline nomination deadlines

•

Trading available through three years (36 months)

Options trading of the Henry Hub natural gas futures contract commenced on October 2, 1992.

Each gas futures contract calls for delivery, in the month specified, of 10,000 MMBtu (or about 974,000 cf) of pipeline quality gas at the Henry Hub in Louisiana. This rather modest contract size is necessary to ensure successful support by the commodity industry, which prefers relatively small units with reasonable margin requirements. In dollar terms, the natural gas contract (assuming $2.00/MMBtu) is worth $20,000, which is of similar order of magnitude as the NYMEX crude oil contract (assuming $20Ibbl). As pointed out earlier, speculative interest is essential in futures trading because speculators take on price risk passed along by hedgers. Hedgers, on the other hand, can be expected to carry multiple contracts positions, often in groups of 100 or even 1,000 contracts. A key element to the successful operation of any futures market is the assurance of a viable delivery mechanism. Henry Hub was selected as the delivery location for gas based on two overall criteria-existence of a competitive spot market characterized by substantial liquidity, and consistency with indus.. try practice-as follows: •

Activity in gas spot markets (liquidity)-number of pipelines with immediate access, number of transacting parties and transactions, delivery capacity, including receipts and transit, volume of gas moved

•

Competitiveness of markets in general, including acceptance by the trading industry, frequency of price quotes, demonstrated reliance on physical deliveries, and psychological comfort level

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The foregoing do not necessarily ensure a successful futures market. Several other gas futures contracts have been introduced since 1990-two others by NYMEX (Permian on May 31, 1996 and Alberta on September 27, 1996)4 and one by the Kansas City Board of Trade (Waha, Texas, starting in August 1, 1995)-but these were experiencing comparatively small trading volumes or nearly none at all by the late 1990s. Even though they generally met the above criteria, their low trading volumes are attributable primarily to the snowballing success of the NYMEX Henry Hub contract. A final point that must be emphasized is that successful futures contracts are generally used as financial planning tools and rarely result in physical delivery of the product traded. In fact, less than 1 % of the natural gas contracts traded on the Exchange are actually delivered. In summary, gas futures trading has fit the gas business and its participants quite well, given the extensive degree of gas spot trading, widespread availability of open non-discriminatory transportation services, and continuing-indeed, rising-price volatility in gas markets in the 1980s and 1990s. The most active users of gas futures have been gas marketing companies, as originally predicted. Regulated gas utilities have been constrained in their ability to use futures because of the nature of the regulatory oversight they experience and their hard-to-measure, often indirect or oblique price risks. As gas utilities gradually relinquish their merchant function to gas marketing companies under stateguided deregulation programs, their need to become involved in gas futures will dissipate even further.

A forward contract is a supply contract between a buyer and seller that obligates the buyer to take delivery, and the seller to provide delivery, of a fixed amount of a commodity at a predetermined price at a specified date. Payment in full is due at the time of or following delivery. (By contrast, for a futures contract settlement is made daily, resulting in partial payment over the life of the contract.)  A swap is custom-tailored, individually negotiated transaction designed to manage financial risk, usually over a period of 1 to 12 years. Swaps can be conducted directly by two counter parties or through a third party such as a bank or brokerage house. The writer of the swap, such as a bank or brokerage house, may elect to assume the risk itself or manage its own market exposure on an exchange. Parties exchange payments based on changes in the price of natural gas, while fixing the

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price they effectively pay for physical delivery. Transaction enables each party to manage exposure to natural gas spot prices. Settlement is usually in cash. Minimizing price risk. Market participants minimize the price risk in the natural gas spot market by taking positions in the financial gas market, sometimes referred to as hedging. Financial contracts enable market participants to take positions in cash (or physical) and financial gas markets to reach an acceptable level of risk. Different levels of risk aversion and the complexity of the gas market create room for market participants to engage in mutually beneficial transactions. Transactions in the financial gas market involve the transfer of price risk between two market participants in exchange for payment. A market participant with high risk aversion is willing to pay a higher premium to get rid of a certain amount of price risk than a participant with low risk aversion. If the participant with low risk aversion can hedge against the price risk, it can acquire the price risk from the participant with high risk aversion. The two participants can then split the difference in premium, and both will be better off than if they minimized the price risk separately. In practice, price risk cannot be diversified away completely because of systemic risk, the risk that is inherent to the market and cannot be diversified away. Market participants can diversify away only no systemic risk, that is, contract- or customer-specific risk. But this requires a sophisticated understanding of hedging strategies and the functioning of markets. The no systemic risk of a contract can be diversified away through a portfolio of cash and financial gas contracts that best Gas traders and other intermediaries are much better able to diversify away no systemic risk than other market participants. They take no systemic price risks from producers, distribution utilities, and other market participants in exchange for premiums and then diversify these risks away by taking positions in physical and financial gas markets. The cost of hedging their positions is lower because they are less risk averse and more sophisticated in hedging strategies than other market participants. Competition among traders pushes premiums down to the least cost of price risk hedging and thus benefits all market participants engaged in financial gas transactions. Minimizing basis risk. The use of financial gas contracts that differ in one or several dimensions from the underlying physical gas contract may result in a difference in the qualitative characteristics of contracted and delivered natural gas. This risk is the basis risk, the uncertainty about whether the

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cash-futures differential will widen or narrow between the time a hedge position is implemented and the time it is liquidated (NYMEX [1996]). The basis risk depends on three price relationships: The relationship between the price of the futures contract and the spot price of gas. This represents cash-futures basis. The relationship between the spot price at the futures contract delivery point and the spot price of a similar but not identical commodity at the same location. This is intercommodity basis. The relationship between the spot price at the futures delivery point and the spot price at a different location. This represents locational basis. Strategies to minimize basis risk differ depending on the type of basis risk involved. Cash-futures basis risk can be minimized by a financial gas contract that specifically addresses the problems. For example, participants in the U.S. financial gas market use the Alternative Delivery Procedures, which allow them to minimize cash-futures price differentials in the period between the expiration date of a futures contract and the start of physical gas delivery. This period ranges from one to five days, depending on the type of futures contract. Hedging inter commodity basis risk is a complex operation that varies from case to case, depending on the kind of commodities involved. If the commodities are commercially traded, market participants can minimize basis risk by taking positions in cash and financial markets in the relevant commodities. If qualitative differences in a commodity are very small and are not commonly traded in the market, such as the difference in the calorific value of natural gas, hedging tools may not be available. In such a case parties must protect themselves by explicitly defining delivery conditions and providing for penalties in the gas supply contracts. Locational basis risk can be managed by a financial gas contract created specifically for this purpose. For example, participants in the U.S. gas industry can use Exchange of Futures for Physicals contracts (EFPs), which allow them to hedge the locational basis risk for almost any delivery location in the United States. Naturally, the efficiency of hedging by EFPs depends on the liquidity of EFPs with the same delivery locations, which in turn depends on the size and liquidity of the spot gas market at a particular location

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OVERALL DIRECTION FOR THE TWENTY-FIRST CENTURY Gas demand in the U.S. and Canada is continuing to grow. Overall North American sales bottomed out in the early mid 1980s and increased strongly in the 1990s. Gas has recaptured the initiative in the home heating market, with installation of gas furnaces currently outpacing electric heat pumps by more than two to one. More importantly, the North American electric power industry has rediscovered natural gas, which is now the preferred fuel for electricity generation because of its abundant supply in fluid markets, economic advantages, financeability, and environmental and safety benefits vs. the altematives--oil, coal, and nuclear power. Some three-quarters of new North American power generation capacity was being installed with natural gas as the primary fuel, as of the turn of the century. Overall gas supplies have remained adequate for market needs, and it is clear that both ample supplies and physical system capacity will continue to exist for the foreseeable future in North America for several reasons: •

First, the sum of proved reserves plus gas resources is large enough to suggest a strong oudook for U.S. gas supplies, one that will oudast any equipment currently being installed to use gas. In 1995, U.S. Geological Survey (in Circular 1118) concluded that 1,106 trillion cubic feet of gas supplies remain to be produced in the U.S. Earlier studies have shown that the majority of this gas is likely to be recovered at competitive prices.

•

Canadian and Mexican natural gas resources together nearly equal those of the U.S. Expansions of TransCanada Pipeline, the Alliance Pipeline, and other major new gas transmission systems were in planning and under construction as of 1999 to transport western Canadian gas to markets throughout the U.S. Growing gas markets in Mexico, particularly for power generation, have attracted suppliers from the U.S. southwest and as far away as Alberta, with the Samalayucca Project in Ciudad Juarez and the Rosarita project in Endenada representing the first in a chain of Mexican power plants fed by natural gas from north of the Rio Grande.

•

As of 1999, a number of major overseas gas suppliers were actively arranging or seeking markets in the U.S. that can be served by importation of LNG at the nation's four existing receiving terminals Everett, MA; Cove Point, MD; Elba Island, GA; and Lake Charles, LA.

With the FERC having nearly completed its own agenda for opening U.S. gas markets, the focus of

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attention and policy debate pertaining to natural gas markets has substantially turned toward the states and to what kinds of regulatory policies they are promulgating with regard to transportation by gas utilities. Industrial and large commercial gas users have participated in open gas trading and markets since the late 1980s. Residential and small commercial customers appeared to be on the threshold of participating in competitive gas markets as of the turn of the century. Through this process of broadening customer awareness at the retail level, many gas marketers and state regulators are optimistic that retail gas deregulation is at hand. Finally, the need to reduce air emissions contributing to the greenhouse effect of global warming is gaining increasing acceptance among policy-makers and fuel consumers. Moreover, U.S. oil imports may well resurface as a national priority, as oil imports continued to rise throughout the 1990s to more than half the nation's consumption of oil and petroleum products. Because of the significant amount of inter-fuel substitution capability in the U.S., expanded sales of natural gas, including Canadian gas, will result from any such policy.

SUMMARY The foregoing chapter may be summarized as follows: •

Long-term, price-regulated contracts between pipelines and producers broke down in the 1980s and disappeared altogether in the 1990s. Most gas is traded by gas marketing companies, and in contracts of one year or less. Gas spot markets currently serve about 40% of U.S. natural gas requirements.

•

Having nearly completed its regulatory reform of gas markets, congressional, state, and FERC emphasis currently lies with reform of electricity markets. As power generation moves toward the independent sector and power markets are deregulated, commercial mechanisms in the electricity industry will rationalize and natural gas demand will increase as a result.

•

Expertise in the commerce of the natural gas business resides within the gas marketing service companies, many of which are affiliated with gas producers, power producers, pipelines, distributors, and even oil traders.

•

Gas futures trading, along with various derivative over-the-counter instruments, has become a crucial mechanism in the gas business. The major gas price identifier in North America is Henry

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Hub (NYMEX or cash markets) plus or minus locational basis, the latter of which is only incidentally related to cost of service on pipelines, or their tariffs. •

After the turn of the century, therefore, despite routine transportation and exchange bottlenecks that will occur on a regional basis (e.g., during winter peak-load seasons), the North American pipeline system will continue to accommodate the gas market successfully, and expand where needed.

Competition among marketers, producers, shippers, and fuels has created an aggressive climate in the North American gas business, with economically attractive pricing. Power markets in the U.S. and natural gas markets in Great Britain, South America, and other places have begun to emulate the unique North American experience, and some elements of the European and Asian markets are likely to follow. Nonetheless, we fully expect the course to continue to evolve in the U.S. and Canada, as new trading and market technologies rise to enable an even more efficient and market responsive gas industry.

Natural Gas Price Formation Market forces that impact natural gas prices include such factors as:

Short-term Demand—Weather patterns impact short-term demand and indeed, the annual cycle of weather has historically been reflected in natural gas prices. An unseasonably cold winter or warmer summer will impact the market's perception of natural gas prices.

Prices of Alternative Fuels—Fuel switching either for electric power generation, or even at the point of energy use, can also play a role in natural gas price formation. This can be reflected in a correlation between commodity prices (e.g., oil products versus natural gas), but it can also have a direct impact on the market's perception of natural gas price formation. An increase in the price of crude oil and its products can be seen as increasing demand for natural gas.

Supply Factors Such as Storage Levels—As stated above, storage levels at above the five year average as determined by the EIA, which ought to suggest that there is plenty of supply for the winter months and thus provide a downward trend in pricing.

Natural Gas Exploration and Production—Natural gas is being depleted faster than new reserves are being added, suggesting that the short to medium-term outlook for natural gas supply is one of steadily decreasing domestic supply. On the other hand, at these prices, exploration

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activity has picked up and one might expect longer-term supply to show an improvement as a result. However, the centers of exploration and future production are also shifting away from traditional producing regions requiring more investment in and construction of infrastructure to deliver gas to the major areas of consumption. Furthermore, natural gas can be imported from other regions such as Canada by pipeline, but also in the form of LNG from overseas. The issue with LNG is that the United States is not the only region with supply/demand tightness in natural gas and thus there is competition for LNG shipments. This means that the price of LNG shipments is higher and the United States often loses out to areas such as Great Britain or Iberia. In fact, the few LNG terminals in the United States that exist today are underutilized.

Long-term Demand—Views on long-term demand from the various types of consumer have also to be taken into account in any fundamental analysis of future natural gas prices. Over the last two years, natural gas demand has actually decreased somewhat but it is generally expected to start to increase again in future years. To some extent, this simply suggests the supply/demand tightness in the United States natural gas market may continue longer.

Speculative Trading—There are many viewpoints about the role of speculative trading in natural gas price formation. Some of the speculative traders use technical trading methods, while others take a more fundamental approach. But it is also these speculative traders that have suffered huge losses periodically in natural gas over the last 12 months. Speculative traders send an additional price signal to others in the market by being net long or net short and in that way impact price formation but they are working with much the same data as everyone else in the market. Certainly, the volume of speculative trades can have a directional effect on price formation and most certainly impacts volatility, but not all speculative traders are betting the same way!

Disruptive News Events—What has become apparent in the last year or so is that disruptive news events are now having a more severe impact on price formation than many of the factors mentioned above. These news events can be real with tangible impact on fundamentals such as last year's hurricanes, or they can be essentially rumors and expectations with no tangible impact on the underlying fundamentals such as the recent Middle East war.

An examination of the losses incurred by the various hedge funds and institutions suggests that many were following fundamentally-based strategies that in previous times ought to have paid off. But in a market with supply/demand tightness (whether real or imagined), their positions were undermined by

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an unexpected disruptive event. For example, many funds shorted natural gas last fall only to be hit by the hurricanes and subsequent loss of production and rise in natural gas prices. Similarly, many funds went short natural gas based on historical patterns and high storage levels only to be caught out by increasing prices due to a very hot summer and perhaps worry about Middle Eastern wars. Challenges in Gas Sector – India 1. Organize competitive supply a. Domestic/ Cross Border 2. Price elasticity & demand build-up 3. Optimal infrastructure development 4. Reforms in electricity markets 5. Policy interventions – Planned deregulation to provide growth thrust 6. Address environmental concerns 7. Align with global markets Deregulation 1. Progressive decontrol of gas prices by government 2. Setting up of Downstream Petroleum Regulatory Board 3. Introduction of Open Access principle 4. Framework of Transportation Tariff determination 5. Unbundling of Transportation and Marketing Transportation Tariff 1. Gas To Gas competition: Innovative Pricing Contracts 2. Concept of pooled pricing 3. Multiple producer prices and multiple consumer prices for new/regional markets

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4. Postalised Vs Distance based transmission tariff – Zonal pricing for high pressure grid and postalised tariff within zone 5. Tariff methodology moving towards international practices – From DCF to Cost of services methodology

Long term supply options Predictions regarding supply of natural gas indicate resources to meet current demand comfortably for the next 60 years. With new discoveries reserves could meet demand for 150 years at the present rate of consumption. Between 2002 and 2025 gas consumption will increase by nearly 70%.The electric power sector will account for almost one –half of the total incremental growth in worldwide natural gas demand over the forecast period .Both pipelines and LNG have a role to play in transporting gas. Pipelines are best for shorter hauls and, thus, should dominate local and regional trade. Generally, LNG is cost competitive only over distances in excess of 4000 kilometres.

Presently, out of the total gas production of 2691 bcm, only 25% is internationally traded.19% gas is being transported through trans national pipelines, and 6% as LNG. Europe is the main importer of gas by pipeline (320 bcm per year) followed by USA importing 102 bcm from Canada. Japan is the principal importer of LNG (77 bcm) followed by Europe (40 bcm), Korea (30bcm) and USA (19 bcm).According to industry forecasts, international trade in natural gas is expected to grow dramatically accounting for one-third of the world output by 2020.This increased trade will cover both LNG and pipeline gas .International trade in LNG is expected to grow at 7% before it reaches 38% of gas trade by 2020.

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CASE: INDIA In India’s changing energy basket gas’s share is expected to increase from 9% to 20%.The bulk of this increase is expected to be used to fuel power projects in order to sustain a growth rate of 8% per year. To achieve this India’s primary energy supply will have to increase three to four times by 2032, while electricity supply would have to increase five to seven times, i.e., power generation would have to increase from 1200000 MW to 778000 MW by 2032. To reach these targets India would need to pursue all available fuel options and energy forms – conventional and non-conventional. All predictions indicate that the maximum contribution of nuclear energy in India’s energy basket can be around 8.8% (in 2032) and 16.4% in 2052.The share of coal which stands at 50 % presently will still be around 40% in 2052, thus it will continue to be the principal fuel in our power projects. As of now, 90% of coal used for power generation is from domestic sources, however, with coal mines depleting and pollution concerns of domestic coal (due to its high ash content) India will have to look at alternatives such as imported coal and imported gas to be used in its power plants. In this case imported gas would have an edge as it is commercially more viable.

DOMESTIC EXPLORATION ACTIVITIES New exploration licensing policy has lead to three fold increase in exploration area in 3 years. A major development in December 2002 was the announcement by Reliance Industries of its discovery of a large amount of natural gas in the Krishna-Godavari Basin offshore from Andhra Pradesh along India's southeast coast. New reserves from this find are estimated at about 14 tcf, the latest announcements in this regard increase the reserves in these fields to 35.5 tcf, thus placing India on the twelfth spot next to Iraq and Indonesia. Reliance had also reported another find offshore from Orissa in June 2004,

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with estimated reserves of 1 Tcf. The company expects production from its Andhra Pradesh fields to commence in 2008. Cairn Energy also reported natural gas finds in late 2002 offshore from Andhra Pradesh as well as Gujarat, which contain reserves estimated at nearly 2 Tcf. ONGC and OIL have made nine significant discoveries in upper Assam and the Rajasthan basin .Private and joint venture companies have also made a few discoveries in the Krishna Godavari basin, Gulf of Cambay and in Rajasthan. Some such gas finds in the recent times are by ONGC, Cairn energy, Niko Resources (Surat on land block of Cambay basin) and Gujarat state petronet limited (20 tcf in offshore fields in the KG basin). Also increased production levels have been achieved in pre NELP fields like Hazira, Panna –Mukta-Tapti, Ravva and PY-3.

PIPELINE NETWORK On September 29th 2003 the government of India announced a draft pipeline gas policy which envisaged laying of 7000 km of pipeline network for gas transportation. As a part of the policy government of India proposes a national gas grid on the pattern of National Power Grid to manage the distribution effectively. The main objective of the draft policy is to put in place a distribution system for carrying gas, the availability of which is likely to improve considerably. Seizing the opportunity GAIL has unveiled a plan to build a 7890 km gas grid.

PIPELINE IMPORT OF GAS Imports of natural gas by pipeline may eventually play a role in satisfying India's gas needs. One possibility would supply India with natural gas from Iran's huge South Pars field via a pipeline through Pakistan. The project has a sound commercial base as Iran has a worlds second largest gas reserves. Iran has discussed the proposal with India and Pakistan. Pakistan is gas dependent with gas constituting 50 per cent of its energy mix while India’s requirement of gas, presently 70 percent in the energy mix is expected to increase very significantly, particularly to provide fuel for the power plant projects in northern, north western and central India. Australia's Broken Hill Proprietary (BHP) is the main foreign backer of the idea. Pakistan had said in early 2001 that it would allow supplies to cross its territory, and Iran would bear the contractual responsibility for assuring gas supplies to India. With the thaw in India-Pakistan relations over the last two years, the project has gained interest, but is still under negotiation. The last two tripartite meetings in March and May addressed the issues of structure

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and price of Iranian gas to be supplied to Pakistan and India. The latter issue has got seriously complicated on account of the recent increases in global oil prices. A new natural gas find in Myanmar also has attracted interest as a potential source of supply for India. Indian companies ONGC and GAIL own a total of 20 percent equity in the reserves, and Bangladeshi officials stated in June 2004 that they would be willing to consider a pipeline running across Bangladeshi territory from Myanmar to West Bengal in India, provided agreement could be reached on terms and transit fees. Myanmar reserves are, perhaps, not as substantial as those of Iran and central Asia. However the countries proximity to India and the fact that the pipeline will not only bring Myanmar gas in India and also enable us to monetize Tripura gas and promote industrial and power projects in our north eastern and eastern regions have made the proposal attractive. Certain problems faced while signing the final MOU have forced India to examine the possibility of transporting Myanmar gas through an overland pipeline skirting Bangladesh or receiving gas as CNG on the east coast.

LNG IMPORTS As most of the pipeline projects could not come up during the last ten years due to various geopolitical and technical issues, it was proposed to import natural gas through LNG route. India's Foreign Investment Promotion Board (FIPB) approved 12 prospective LNG import terminal projects in the midto-late-1990s, but it was never considered likely that all would be built in the near future, as their combined capacity would have exceeded even the most optimistic demand projections. The Indian government froze approvals of new LNG terminals in 2001, and payment problems at the Enronbacked Dabhol Power Plant in Maharashtra led many to question the financial viability of some of the LNG import projects. Reforms currently being undertaken in the electric power sector may eventually change this situation. The largest state sector projects are to be conducted by Petronet, a joint venture between ONGC, IOC, the Gas Authority of India Ltd. (GAIL), the National Thermal Power Corporation (NTPC), and Gaz de France. Each of the state firms owns a 12.5 percent stake, the Gujarat state government owns a 5 percent stake, and the rest is owned by private investors, including a 10 percent stake held by Gaz de France Petronet plans two import terminals, one at Dahej and the other at Kochi. The import terminal at Dahej began operation in 2004, receiving India's first cargo of LNG on January 30, 2004. The Dahej terminal had major advantages over some of the other proposed projects, because it is tied in with the

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main state-owned natural gas company, GAIL, and the existing HBJ pipeline network. After several delays, Petronet is planning to solicit bids for its second terminal at Kochi in early 2006, with a planned completion in 2009. Shell also has begun construction of its LNG import terminal at Hazira in Gujarat, it received its first LNG cargo on the 17 th April, 2005 from north west Shell project in Australia .Like the Petronet Dahej terminal, it is to be linked into existing natural gas pipelines, its first customer was GSPC.Shell reportedly has been in discussions with Indian companies about a possible sale of a percentage of its equity in the terminal. Enron’s Dabhol LNG terminal, which has been idle for the last few years, is now being revived by the new management, Ratnagiri Gas and Power Pvt.Limited.In this case also it has not been possible to tie up a long term supply of LNG due to limited availability internationally, as also the desire to secure the best possible price. Meanwhile, the plant has been started on naphtha, which had been acquired earlier.Supplies of LNG from Iran may also be an option in the future, and a consortium of Indian companies signed preliminary memorandum of understanding in June 2005 for sales of LNG to supply the two Petronet terminals, beginning in 2009 after the completion of the Kochi terminal. Iran agreed to supply

to

India

5

mmtpa

of

LNG

at

3.215

dollars

May 2006 Iran expressed its desire to renegotiate the deal. TABLE 10 Existing and Proposed LNG Terminals in India

LNG Terminal

(mmtpa)

LNG Capacity

Existing/under Expansion and Revival Dahej

5

Dahej expansion

5

Shell Hazira

2.5

Dabhol(revival)

2.5

New Proposal

245

per

mmbtu

FOB.

However,

in

Kochi Mangalore Kakinada TOTAL

2.5 5 2.5 25

Source: www.safan.com

OVERSEAS ACQUISITIONS Another option to enhance energy supply is to encourage indigenous companies to explore in other countries thereby increasing equity energy reserves. OVL has nine overseas assets and is actively seeking more opportunities across the world. With a long term target of acquiring 60 mmtpa of equity oil and gas overseas by 2025, OVL is currently working towards a goal of 20 mmtpa by 2010. Some of OVL’s investments are in Sakhalin oil fields of Russia (us$1.7 billion), 25% share in GNOP fields of Sudan (us$720million), Vietnam project where gas production would start in 2008. OVL has also decided to invest us $1 billion in Sudan .earlier OVL acquired 25% equity in Sudan’s grater Nile project for us $669 million. A consortium of OVL, IOC, and OIL has also signed a contract with the National Iranian Oil Corporation for exploration of Fars offshore block in the Persian Gulf. In addition, OVL has also collaborated with other international majors to obtain equity oil and gas. The Consortium of OVL-GAILDAEWOO-KOGAS has discovered a world-class giant gas field in Block A –I offshore northwest Myanmar. ONGC and China’s state-owned China National Petroleum Company (CNPC) are also exploring possibilities of taking up oil equity jointly in third countries. In April 2004, OVL had cut a deal with Dutch Shell to buy its 50 per cent stake in the offshore Block 18 for $623 million. OVL is in the process of intensifying the efforts with Angola to secure clearance for the acquisition of 50 per cent interest in an oilfield in the oil-rich African country. A stake in Block 18, of which British Petroleum holds the remaining 50 per cent, will give India close to 5 million tonnes of crude oil annually from 2008-09. Recently OVL has acquired a majority interest in an oil block in Australia. As per the agreement OVL will acquire 55 per cent interest in the block located in the northwest shelf in offshore Australia, from

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Canadian firm Antrim Energy Inc. Antrim, which currently holds 87.5 percent stake in the block, estimates up to 500 million barrels of recoverable oil in the block. The first well in the browse basin of the northwest shelf could yield 150 million barrels of recoverable oil. Over the last half century, our use of natural gas has grown steadily –driven by intrinsic advantages such as being a safe, clean, burning fuel. Today, natural gas provides a vitally important and growing proportion of the world’s energy. Yet, even as there is concern over the depletion of oil reserves, analysts believe similar concerns about natural gas may crop up in the near future. As the countries have started giving increasing importance to energy security and with their dependence on expensive imports, the previously under exploited sources have become the targets of intense interests. In this scenario the world is looking towards unconventional sources of energy.

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