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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 significan

importance as a valuable source of energy internationally. Natural gas is now gaining prominence a

the fuel of the future as it meets clean fuel requirements and is cost effective for major industries, a

compared to traditional fuels such as coal and naphtha. Gas assets in India did not receive muc

attention till few years back. However, mounting oil bills and need for cleaner fuels has necessitate

the country to explore its gas potential. Supply deficit has long been a significant feature of Indias ga

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 Exploratio

and Licensing Policy (NELP), private players have been allowed to participate in exploration an

production of natural gas. Currently, the two PSUs still account for 83 percent of domestic ga

production. Marketing of gas and pipeline infrastructure is undertaken by GAIL India Ltd. Companiesuch 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 tw

primary sectors which together account for close to 80 percent of the gas consumption. Besides, othe

sectors such as petrochemicals, sponge iron and transportation also consume natural gas. Deman

for natural gas in India for 2003-04 was estimated at 98 mmscmd (million standard cubic metres pe

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 energ

consumption as compared to 24 percent worldwide. According to India Hydrocarbon Vision 202

report, demand for natural gas is expected to show a sharp rise in the future with the demand reachin

to 391 mmscmd by 2024-25. The report also expects that the share of natural gas in total energy mi


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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, worl

trade in natural gas has also increased at a CAGR of about 8% over the past 28 years. Between 200

and 2002, both pipeline exports and LNG exports grew by 4.9%. Projected increases in consumptio

will require bringing new gas resources to the market. Numerous international pipelines are eithe

planned or are already under construction. The development of liquefaction technology, the need totransport natural gas over long distances across oceans, coupled with cost decreases throughout th

LNG chain, has made LNG more economical, and led to expectations of strong growth in internationa

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 b

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 natura

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 ga

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 i

traded via pipelines. Asia Pacific accounted for about 70% of total LNG imports in 2002 followed b

Europe and North America. Japan and South Korea are the key markets for LNG, where natural ga

cannot be supplied through pipelines. Japan is the largest importer of LNG in the world, an

accounted for 48.5% of total LNG imports in 2002. LNG imports in most countries are backed by th

Government or state-owned entities, like Kogas in South Korea, China Petroleum Corp in Taiwan, an

Gaz de France in France. In Japan, the importing agencies are power utilities for captive use of natura

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 the

product at a price that is sufficient to cover their capital costs, which includes take-or-pay and floo

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 t

have a community of interest between the buyer and the seller. A successful LNG Project must hav

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 increasing

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 o

imported naphtha and condensates will not be able to compete with natural gas, although increase

domestic production could affect demand for gas imports. For now, gas imports via pipeline an

increased domestic naphtha production remain more distant possibilities; meanwhile both th

government and private industry are pursuing LNG imports. There are plans for several LNG project

at various stages of materialization, and many plans are still changing. Nevertheless, the earlies

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 price

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 lowe

per capital income. It produces some domestic oil and gas (although potentially under-explored), an

has some existing pipeline infrastructure. India's large agricultural sector means that the fertilizeindustry (and petro-chemicals in general) will facilitate increasing use of natural gas in the domesti

economy. While China could conceivably also benefit from a strong fertilizer industry, its pipelin

infrastructure is less developed, and what does exist may not be as helpful as India's major ga

pipeline running inland from the Western coast with several spurs. Still, like much of Asia, neithe

China nor India currently has extensive gas infrastructure for supplying residential or commercia

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 consumptio

grew by 3.5% in 2002, coal marginally increased its share in the energy mix from 54.9% in 2001 t

55.6% in 2002, and oil lost share marginally from 30.8% to 30%. Natural gas maintained its share a


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7.8%. Going forward, as per estimates, the total share of oil and gas in the primary energy mix is no

expected to change substantially. However, gas, owing to its non-polluting nature and ease of use a

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 th

demand for natural gas in India. With gas' share in the primary energy mix projected to increase t

15% by 2007 according to the Hydrocarbons Vision 2025 report, the demand for natural gas i

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 als

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 Bomba

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

shortage of gas, and this demand-supply gap is projected to increase with strong growth in deman

vis--vis plans to bridge this gap by resorting to alternate sources of gas. This strategic importance onatural gas for the Indian economy coupled with a shortage of supply and its recognition by the Go

has had an impact on the evolution of the fiscal and regulatory environment for natural gas .

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only a desk, a computer, and a telephone to contact customers and make deals. As a result, th

optimal size of a gas trader or supplier is small relative to the gas market. This optimal size increase

with deregulation of the industry because markets become more complex, with increasing use o

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 i

the new markets (about 85%) are in the fields of electricity production, chemical usage and some othe

big consuming sectors. This fact alone restricts the potential for development, and as a result thimport projects are mostly linked to electricity production projects; this is a well-known pattern alread

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 producer

using combined cycle gas turbine equipment. In future, however, it will also be severely restricted b

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 unde

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 spot

traded LNG destined for the US. In order to expand their LNG sales, the oil majors, among others, ar

no longer remaining idle in the position of investors, interest holders and/or suppliers of LNG in th

upstream sector. They are adopting the strategy of becoming LNG buyers themselves and ar

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 wh

the US-bound LNG spot trading is ballooning so rapidly. This concept is becoming real in the Atlanti


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market, as demonstrated by expanding spot transactions. In the Asia/Pacific market too, introductio

of a similar strategy is under consideration. LNG terminal construction projects and commercializatio

of on-board gasification technology on the U.S. West Coast, among others, all point to this concep

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 ga

pricing mechanisms. Though Asia dominates the growing world LNG trade, LNG accounts for only

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 ga

market to which Asian countries can link heir domestic natural gas prices. In some with the prices ofuel oil. In other countries, including China and India, natural gas prices are determined and regulate

by the governments, often set at low levels to benefit industrial sectors, or to subsidize the residentia

sector in areas adjacent to natural gas fields. Excessive government intervention in natural gas pricin

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 leve

of gas consumption in Asia. Promoting gas consumption did not become a priority for Asia

governments until the economic boom of the 1980s generated the skyrocketing energy needs of th

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

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 towar

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 it

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 it

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

fixed delivery portion (separation of price and flexibility) Many options of pricing formula will b

available in the future. It is also possible to arrange a wide variety of LNG contracts by pairing differen

pricing formulas with various trading patterns, each having flexibility of its own (e.g. long, medium an

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 facilitat

interactions among market participants with the objective of achieving simultaneous clearing of natura

gas and transportation markets at minimum cost to the gas industry. Deregulation of the natural ga

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 t

complete all their transactions at the minimum cost. While a vertically integrated gas compan


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optimizes all transactions internally, participants in a deregulated gas industry must coordinate the

natural gas and transportation transactions in an open market. The process of minimizing the total cos

of natural gas and transportation to the industry must take place across thousands of decentralize

transactions. Unless these transactions are guided by a trading model, they can result in sub optima

allocation of resources.

Bilateral trading model

The bilateral trading model is based on decentralized bilateral transactions. The model relies o

competitive gas and transportation markets to generate efficient prices and minimize the cost o

natural gas to the end users.

Decentralized spot markets

In the bilateral trading model market participants conclude all deals in bilateral negotiations and writ

contracts that address all issues relevant to a transaction. Demand for ways to minimize of transactiocosts leads to the emergence of traders who complete transactions on behalf of other marke

participants. Spot markets develop as market participants require efficient pricing of natural gas a

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 marke

participants the right incentives to complete transactions efficiently. As a result, decentralized bilatera

trading among market participants achieves the outcome that is optimal for individual participants a

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 fixe

and variable costs of a pipeline company per unit of distance over which individual shipments tak

place. A capacity charge is set to recover total fixed costs, while a throughput charge is used t

recover the variable costs of transporting natural gas. Transportation contracts sold in the secondar

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 interruptibl

transportation contracts enable shippers to match their needs for natural gas with transportatio


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services. They form a portfolio of transportation contracts that gives them the minimum acceptabl

reliability of transportation at the minimum cost. Because each shipper is able to minimize its total cos

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 conducte

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 i

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 competitiv

transportation market than model 3.


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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 a

extraordinarily competitive, robust business, one that has become the commercial model for ga

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. Electroni

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-lik

business operating under heavy-handed economic regulation. This chapter traces the growth of ope

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 market

worked as of the turn of the century, including spot and long-term contracting, gas futures an

derivatives, and trading of transportation and storage capacity. A final section then projects where ke

trading and futures developments appear to be leading the North American gas industry.

BACKGROUNDNatural 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 delivere

into any major gas pipeline system, natural gas is a completely fungible commodity composed chiefl

of methane, with trace amounts of propane, carbon dioxide, and other gases. Natural gas in pipeline

is virtually free of sulfur and is odorless; that common odor of natural gas is actually mercaptan-a sub

stance injected for identification (safety) purposes.

Gas is produced in 25 states and six provinces of the U.S. and Canada, respectively, includin

onshore and offshore producing fields. Most gas used in North America (75%) is produced from ga

wells-the remainder is produced in association with oil. The continent is largely self-sufficient in natura

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 i

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 ga

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 completelchange the way it bought and sold gas. From the Phillips decision in 1954 through the initial ga

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 th

business. That is: gas was sold by producers under long-term contracts primarily to regulated pipelin

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 temporar

unemployment of more than one million people in the winter of 1977-resulted in passage of the Natura

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 price

controlled gas was?

From the enactment of the NGPA through 1982, the gas industry resumed its long-term contractin

practices in a period of intense exploration and development efforts, buoyed by high and seemingl

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 turne

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 a

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 suppl


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and demand for a commodity. Spot gas markets evolved in the U.S. and Canada throughout th

1980s and 1990s in increasingly fluid trading environments. Throughout the North American ga

industry, reported spot gas prices have become the gas industry's standard reference for gauging fa

market value. By 1998, four of every five units of natural gas were traded in contracts of one year o

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 procuremenof pipeline capacity in equally short-term markets. Such transportation arrangements consist o

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" transportatio

arrangements. Gas and transportation trading now commonly takes place throughout the industry a

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 ga

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. Fo

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 spomarket as an alternative channel. In particular, pricing provisions in term contracts are written wit

reference to prices reflective of gas spot markets (e.g., Henry Hub NYMEX futures or spot gas plus o

minus a locational basis--explained below-as well as averages of indices reported in trade press, spo

price reports at several pipeline inlets, and more).

Where customers must borrow or spend substantial sums on gas-consuming equipment, sti

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. Th

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 conduc

gas trading, including buying and selling gas, trading pipeline capacity, arranging transportatio

through gas distributors, and otherwise facilitating markets. By 2000, the numbers had not change

greatly but the composition changed, with more marketersinvolved in a wide variety of additional trading activities, including electricity, power generatin

capacity, financial risk management and local residential and commercial gas services. Overal

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 th

industry-producers, pipelines, and LDCs) formed gas marketing subsidiaries to capture newl

recognized profit opportunities and often simply to facilitate gas transportation. The FERC responde

by issuing rules and otherwise acting to prevent pipeline-affiliated gas marketers to secure marke

advantages. With the advent of gas futures trading in 1990, the gas marketing industry grew intensel

competitive, with many financial services companies becoming involved in gas marketing. By the lat

1990s, as understanding of the benefits of this industry grew, more firms from different industrie

entered the business, including independent power generators, fuel oil distributors, merchandising an

retail firms, and more.

TRANSPORTATION CAPACITY TRADING AND "BASIS"

Trading of pipeline and storage capacity takes place in primary and secondary markets, although thtwo mechanisms are economically intertwined and often indistinguishable.

Primary capacity markets consist of a set of contracts, typically either firm or interruptible, betwee

the physical pipeline and storage asset owners and gas shippers. Secondary markets consist o

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 fo

shipping spot and other direct market gas were made entirely in primary markets, i.e., firm an

interruptible transportation contracts directly to shippers. By the late 1990s, secondary capacit

markets had grown in importance to at least equal primary markets, with capacity release as the majo

trading instrument. Indeed, primary and secondary transportation markets have melded into a fairl


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competitive commodity trade in pipeline capacity, whose currency (i.e.,the price variable) is referred t

as "basis."

Basis competition dominates markets for gas pipeline capacity. The basis differential (or simpl

basis) is defined as the difference in the value of gas, the commodity, at one location vs. anothe

location. As competitive pipeline capacity markets gained in trading activity, competitive basis differen

tials emerged among dozens of market centers, or hubs, throughout North America. Basis need noequate to cost-ofservice transportation rates on pipelines. Instead, basis is determined by supply

demand balances in different markets and, as a consequence, constitutes a valid measure of th

value that markets place on pipeline capacity at any point in time.! If points A and B both represen

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, the

the basis differential is $.15/Mcf. Thus, pursuing this example, if we assume that the pipeline

maximum transportation rate to haul gas from A to B equals $.25/Mcf, then basis in secondar

markets works as follows:

If basis is less than maximum rates, then releasing shippers typically discount to meet basis:2 Apa

from long-term contract arrangements that may be in force, no releasing shipper can reasonabl

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 collec

maximum rates would at least encounter basis competition: a shipper in our example would sell off th

gas at A for $2.00/Mcf, and repurchase gas at B for $2.15/Mcf, calling the loss of $.15/Mcf the cost o"transportation" from A to B. Thus, basis limits the rates releasing shippers can charge over a period o

time.

If basis exceeds maximum rates, then releasing shippers are limited to charging below market rates fo

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 o

$.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 a

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 t

do with pipeline's cost-of-service rates, but instead, they relate more directly to the nexus of suppl

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 mechanism

described below are intended only as an approximate guide to the basic flows of information and wi

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 commercia

arrangements for gas supplies in the next month. Such arrangements are not limited to biweek, and may take place throughout the month via phone, fax, the Internet, and/or pipeline

based and other electronic bulletin boards.

Within approximately a week before the end of each month, those planning to physicall

transport gas on pipelines (known as shippers) make or confirm their transportatio

arrangements either directly from pipelines' transportation departments or in secondary market

by bidding for and obtaining released pipeline capacity.

As required by their capacity arrangements, shippers then submit nominations for dailtransportation capacity to pipelines over the next month, identifying expected daily ga

volumes, receipt and delivery points, and other key information.

Over the next hours or day, pipeline capacity reconciliation staff review nominations an

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 hedg

arrangements, EFPs and other transactions. As required, credit and related information i

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 fo


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the new month and final transportation arrangements are made-hurriedly at times. At this point, an

final changes to transportation pricing are also agreed upon to the extent warranted by capacity an

competition.

Throughout the month, trade publications report gas prices at some three-dozen geographica

points on a daily and weekly basis. Increasingly, the business is also relying on the Internet, pipeline

based 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., fo

power generation and industrial uses), and improved price reporting and averaging (e.g.,on-scree

changes throughout the day).

Financial gas market

The financial gas market is the market place where financial gas contracts are traded. A financial ga

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 play

an important role. The main intermediaries are traders and financial institutions, such as banks an

organized exchanges.

Financial gas contracts are highly variable because of the heterogeneity of needs of marke

participants. The most common types of contract are forward contracts, swaps, futures contracts, an

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 th

Exchange's biggest successes, with open interest nearly two thirds of NYMEX crude oil as of the lat

1990s-impressive because natural gas is a North American market, while crude oil is worldwide. I

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 th

futures market to buy or sell natural gas and the commodity exchange. The party agrees to accept o

deliver, during a specified month, a certain quantity of natural gas meeting quality and deliver

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 ar

settled daily based on their current market value.

Future contracts are essentially agreements to buy or sell a given quantity of a particular share fo

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 underlyin

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 profit

and losses are paid between buyer and seller with a final payment made at delivery. For an index

based contract, the question of final payment of delivery does not arise since all such contracts will becash 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 g

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

falls as the instrument price falls. With a short position, a loss ensues if the instrument price rises bu

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 amon

individuals with different risk bearing capacities e.g. hedgers (who want to reduce risk) an

speculators (who want to acquire more risk). It is the interaction between hedgers and speculators thanot 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 futur

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 underlyin

instrument, the combined position is said to be hedged .i.e. the risk of changes in value to th

combined position is reduced or removed.

A financial gas market tends to develop once the physical gas market has reached a certain maturit

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 b

customer-specific contracts, developed by financial intermediaries and traders to suit the needs o

individual clients producers, distribution utilities, and large end users seeking to minimize the pric

risk they face in the physical gas market.

Demand for financial gas contracts increases as the physical gas market matures. The concentratio

of gas trading in spot markets facilitates the development of standardized financial gas contracts, suc

as futures and options contracts, that are developed and supplied by organized exchanges. Fo

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 fo

delivery in four major spot markets in the United States and Canada Financial gas contracts serve tw

main purposes. They minimize the price risk in the natural gas spot market, and they minimize th

basis risk resulting from the imperfect match between physical and financial gas contracts. They als

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 discover

tools, promoting increased competition in markets. Futures prices are widely disseminated an

available to all regardless of whether or not they are involved in futures market trading per se. I

particular, NYMEX gas futures prices are carried by The New York Times, The Wall Street Journa


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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 ga

spot and NYMEX Henry Hub futures prices has been excellent (rsquared coefficient of 98.95% i

1997). With this high degree of price exposure and confidence, it is not surprising that Henry Hub ga

has become the standard price index for the North American continent, and NYMEX and/or Henry Hu

cash prices are commonly found in long-term contracts as the parties' agreed upon index. Pricreferencing 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 future

market.

Risk management. Trading of commodity futures provides a mechanism to cope with fluctuatin

prices through the process of hedging, i.e., exchanging uncertain cash flows in physical marke

transactions with certain cash flows in futures market transactions. Gas marketers are especiall

prone to hedge on the NYMEX Henry Hub futures market because they experience price risk on bot

sides of their transactions, i.e., buying and selling gas in physical markets. By taking positions i

commodity markets, they effectively lock in prices at known levels, rather than await future pric

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 it

reserves by selling a futures contract. For example, suppose that in January, the futures price o

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. B

selling into the futures market, ShortCo has locked in a price of $2.00 per MMBtu. When the end o

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 los

will be offset by the $.50 per MMBtu gain in the value of its gas reserves. The point is that, in eithe

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 o


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lower than expected, at least insofar as the hedged volumes were concerned. The hedger's goal wa

to shed risk, as opposed to the goal of the speculator, who is discussed further below. The example o

the long hedge works in a parallel but opposite way: LongCo, a manufacturer, has promised to delive

the goods it produces at a fixed price, despite the risk of considerable increases in its production cost

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 actuallrise, LongCo's increase in production costs will be offset by the profit made in selling the gas future

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 i

which brings up the third major function of a futures market-investment opportunity and the role of th

speculator. The principal attraction of futures markets to the speculator is the high leverage an

accompanying profit potential produced by low margin requirements. Speculators are attracted t

volatile markets, where prices fluctuate frequently. Natural gas is no exception. However, unlike th

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

position, hoping that the price will move in their favor, leaving them with a profit. The private funds tha

flow to commodity trading provide the necessary liquidity and a fresh source of risk capital to th

natural gas industry.

NYMEX GAS FUTURES CONTRACT

A approved by the Commodity Futures Trading Commission (CFTC) in 1990 and modified throughou

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 deliverie

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 th


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Texas-Louisiana Gulf Coast region with direct or indirect service toevery gas market in Nort

America

Natural gas meeting standard pipeline quality specifications, thus acceptable for transportatio

on any major pipeline

Arrangements for exchanges of futures for physicals (EFP), alternative delivery procedure

(ADP),and other options

Trading cessation three business days before the end of the month toallow time tocomplet

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 abou974,000 cf) of pipeline quality gas at the Henry Hub in Louisiana. This rather modest contract size i

necessary to ensure successful support by the commodity industry, which prefers relatively small unit

with reasonable margin requirements. In dollar terms, the natural gas contract (assumin

$2.00/MMBtu) is worth $20,000, which is of similar order of magnitude as the NYMEX crude o

contract (assuming $20Ibbl). As pointed out earlier, speculative interest is essential in futures tradin

because speculators take on price risk passed along by hedgers. Hedgers, on the other hand, can b

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 overa

criteria-existence of a competitive spot market characterized by substantial liquidity, and consistenc

with indus.. try practice-as follows:

Activity in gas spot markets (liquidity)-number of pipelines with immediate access, number o

transacting parties and transactions, delivery capacity, including receipts and transit, volume o

gas moved

Competitiveness of markets in general, including acceptance by the trading industry, frequenc

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 future

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, startin

in August 1, 1995)-but these were experiencing comparatively small trading volumes or nearly none a

all by the late 1990s. Even though they generally met the above criteria, their low trading volumes areattributable 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 a

financial planning tools and rarely result in physical delivery of the product traded. In fact, less than

% 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 th

extensive degree of gas spot trading, widespread availability of open non-discriminatory transportatio

services, and continuing-indeed, rising-price volatility in gas markets in the 1980s and 1990s. Th

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 state

guided 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 tak

delivery, and the seller to provide delivery, of a fixed amount of a commodity at a predetermined priceat 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 o

through a third party such as a bank or brokerage house. The writer of the swap, such as a bank o

brokerage house, may elect to assume the risk itself or manage its own market exposure on a

exchange. Parties exchange payments based on changes in the price of natural gas, while fixing th


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price they effectively pay for physical delivery. Transaction enables each party to manage exposure t

natural gas spot prices. Settlement is usually in cash.

Minimizing price risk.Market participants minimize the price risk in the natural gas spot market b

taking positions in the financial gas market, sometimes referred to as hedging. Financial contract

enable market participants to take positions in cash (or physical) and financial gas markets to reach a

acceptable level of risk. Different levels of risk aversion and the complexity of the gas market creat

room for market participants to engage in mutually beneficial transactions.

Transactions in the financial gas market involve the transfer of price risk between two marke

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.

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 i

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 sophisticate

understanding of hedging strategies and the functioning of markets. The no systemic risk of a contrac

can be diversified away through a portfolio of cash and financial gas contracts that best Gas trader

and other intermediaries are much better able to diversify away no systemic risk than other marke

participants. They take no systemic price risks from producers, distribution utilities, and other marke

participants in exchange for premiums and then diversify these risks away by taking positions i

physical and financial gas markets. The cost of hedging their positions is lower because they are les

risk averse and more sophisticated in hedging strategies than other market participants. Competitio

among traders pushes premiums down to the least cost of price risk hedging and thus benefits a

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 o

contracted and delivered natural gas. This risk is the basis risk, the uncertainty about whether th


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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

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 differen

location. This represents locational basis.

Strategies to minimize basis risk differ depending on the type of basis risk involved. Cash-futures basi

risk can be minimized by a financial gas contract that specifically addresses the problems. Fo

example, participants in the U.S. financial gas market use the Alternative Delivery Procedures, whicallow them to minimize cash-futures price differentials in the period between the expiration date of

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, marke

participants can minimize basis risk by taking positions in cash and financial markets in the relevan

commodities. If qualitative differences in a commodity are very small and are not commonly traded i

the market, such as the difference in the calorific value of natural gas, hedging tools may not b

available. In such a case parties must protect themselves by explicitly defining delivery conditions an

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 Physical

contracts (EFPs), which allow them to hedge the locational basis risk for almost any delivery locatio

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 bottome

out in the early mid 1980s and increased strongly in the 1990s. Gas has recaptured the initiative in th

home heating market, with installation of gas furnaces currently outpacing electric heat pumps b

more than two to one. More importantly, the North American electric power industry has rediscovere

natural gas, which is now the preferred fuel for electricity generation because of its abundant supply ifluid markets, economic advantages, financeability, and environmental and safety benefits vs. th

altematives--oil, coal, and nuclear power. Some three-quarters of new North American powe

generation capacity was being installed with natural gas as the primary fuel, as of the turn of th

century.

Overall gas supplies have remained adequate for market needs, and it is clear that both ampl

supplies and physical system capacity will continue to exist for the foreseeable future in North Americ

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 t

use gas. In 1995, U.S. Geological Survey (in Circular 1118) concluded that 1,106 trillion cubi

feet of gas supplies remain to be produced in the U.S. Earlier studies have shown that th

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 ga

transmission systems were in planning and under construction as of 1999 to transport wester

Canadian gas to markets throughout the U.S. Growing gas markets in Mexico, particularly fo

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 Endenad

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 existin

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 o


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attention and policy debate pertaining to natural gas markets has substantially turned toward th

states and to what kinds of regulatory policies they are promulgating with regard to transportation b

gas utilities. Industrial and large commercial gas users have participated in open gas trading an

markets since the late 1980s. Residential and small commercial customers appeared to be on th

threshold of participating in competitive gas markets as of the turn of the century. Through this proces

of broadening customer awareness at the retail level, many gas marketers and state regulators aroptimistic that retail gas deregulation is at hand.

Finally, the need to reduce air emissions contributing to the greenhouse effect of global warming i

gaining increasing acceptance among policy-makers and fuel consumers. Moreover, U.S. oil import

may well resurface as a national priority, as oil imports continued to rise throughout the 1990s to mor

than half the nation's consumption of oil and petroleum products. Because of the significant amount o

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 1980

and disappeared altogether in the 1990s. Most gas is traded by gas marketing companies, an

in contracts of one year or less. Gas spot markets currently serve about 40% of U.S. natura

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 towar

the independent sector and power markets are deregulated, commercial mechanisms in th

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

crucial mechanism in the gas business. The major gas price identifier in North America is Henr


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Hub (NYMEX or cash markets) plus or minus locational basis, the latter of which is onl

incidentally related to cost of service on pipelines, or their tariffs.

After the turn of the century, therefore, despite routine transportation and exchange bottleneck

that will occur on a regional basis (e.g.,during winter peak-load seasons), the North America

pipeline system will continue to accommodate the gas market successfully, and expand wher

needed.

Competition among marketers, producers, shippers, and fuels has created an aggressive climat

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 th

unique North American experience, and some elements of the European and Asian markets are likel

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 ga

industry.

Natural Gas Price Formation

Market forces that impact natural gas prices include such factors as:

Short-term DemandWeather patterns impact short-term demand and indeed, the annual cycl

of weather has historically been reflected in natural gas prices. An unseasonably cold winter o

warmer summer will impact the market's perception of natural gas prices.

Prices of Alternative FuelsFuel switching either for electric power generation, or even at th

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

direct impact on the market's perception of natural gas price formation. An increase in the price o

crude oil and its products can be seen as increasing demand for natural gas.

Supply Factors Such as Storage LevelsAs stated above, storage levels at above the five yea

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 ProductionNatural gas is being depleted faster than new

reserves are being added, suggesting that the short to medium-term outlook for natural gas suppl

is one of steadily decreasing domestic supply. On the other hand, at these prices, exploratio


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activity has picked up and one might expect longer-term supply to show an improvement as

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 t

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 issu

with LNG is that the United States is not the only region with supply/demand tightness in naturagas and thus there is competition for LNG shipments. This means that the price of LNG shipment

is higher and the United States often loses out to areas such as Great Britain or Iberia. In fact, th

few LNG terminals in the United States that exist today are underutilized.

Long-term DemandViews on long-term demand from the various types of consumer have als

to be taken into account in any fundamental analysis of future natural gas prices. Over the last tw

years, natural gas demand has actually decreased somewhat but it is generally expected to start t

increase again in future years. To some extent, this simply suggests the supply/demand tightnes

in the United States natural gas market may continue longer.

Speculative TradingThere are many viewpoints about the role of speculative trading in natura

gas price formation. Some of the speculative traders use technical trading methods, while other

take a more fundamental approach. But it is also these speculative traders that have suffered hug

losses periodically in natural gas over the last 12 months. Speculative traders send an additiona

price signal to others in the market by being net long or net short and in that way impact pric

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 certainlimpacts volatility, but not all speculative traders are betting the same way!

Disruptive News EventsWhat has become apparent in the last year or so is that disruptiv

news events are now having a more severe impact on price formation than many of the factor

mentioned above. These news events can be real with tangible impact on fundamentals such a

last year's hurricanes, or they can be essentially rumors and expectations with no tangible impac

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

market with supply/demand tightness (whether real or imagined), their positions were undermined b


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an unexpected disruptive event. For example, many funds shorted natural gas last fall only to be hit b

the hurricanes and subsequent loss of production and rise in natural gas prices. Similarly, many fund

went short natural gas based on historical patterns and high storage levels only to be caught out b

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 an

postalised tariff within zone

5. Tariff methodology moving towards international practices From DCF to Cost of service

methodology

Long term supply options

Predictions regarding supply of natural gas indicate resources to meet current demand comfortably fo

the next 60 years. With new discoveries reserves could meet demand for 150 years at the present rat

of consumption. Between 2002 and 2025 gas consumption will increase by nearly 70%.The electri

power sector will account for almost one half of the total incremental growth in worldwide natural ga

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 i

being transported through trans national pipelines, and 6% as LNG. Europe is the main importer o

gas by pipeline (320 bcm per year) followed by USA importing 102 bcm from Canada. Japan is th

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% o

gas trade by 2020.


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CASE: INDIA

In Indias changing energy basket gass share is expected to increase from 9% to 20%.The bulk of thi

increase is expected to be used to fuel power projects in order to sustain a growth rate of 8% per year

To achieve this Indias primary energy supply will have to increase three to four times by 2032, whil

electricity supply would have to increase five to seven times, i.e., power generation would have t

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 nuclea

energy in Indias energy basket can be around 8.8% (in 2032) and 16.4% in 2052.The share of coa

which stands at 50 % presently will still be around 40% in 2052, thus it will continue to be the principa

fuel in our power projects. As of now, 90% of coal used for power generation is from domesti

sources, however, with coal mines depleting and pollution concerns of domestic coal (due to its hig

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 majo

development in December 2002 was the announcement by Reliance Industries of its discovery of

large amount of natural gas in the Krishna-Godavari Basin offshore from Andhra Pradesh along India'

southeast coast. New reserves from this find are estimated at about 14 tcf, the latest announcementin this regard increase the reserves in these fields to 35.5 tcf, thus placing India on the twelfth spo

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 hav

made nine significant discoveries in upper Assam and the Rajasthan basin .Private and joint ventur

companies have also made a few discoveries in the Krishna Godavari basin, Gulf of Cambay and i

Rajasthan. Some such gas finds in the recent times are by ONGC, Cairn energy, Niko Resource(Surat on land block of Cambay basin) and Gujarat state petronet limited (20 tcf in offshore fields i

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 whic

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 th

distribution effectively. The main objective of the draft policy is to put in place a distribution system fo

carrying gas, the availability of which is likely to improve considerably. Seizing the opportunity GAI

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 pipelin

through Pakistan. The project has a sound commercial base as Iran has a worlds second largest ga

reserves. Iran has discussed the proposal with India and Pakistan. Pakistan is gas dependent wit

gas constituting 50 per cent of its energy mix while Indias requirement of gas, presently 70 percent i

the energy mix is expected to increase very significantly, particularly to provide fuel for the power plan

projects in northern, north western and central India. Australia's Broken Hill Proprietary (BHP) is th

main foreign backer of the idea. Pakistan had said in early 2001 that it would allow supplies to cros

its territory, and Iran would bear the contractual responsibility for assuring gas supplies to India. Wit

the thaw in India-Pakistan relations over the last two years, the project has gained interest, but is sti

under negotiation. The last two tripartite meetings in March and May addressed the issues of structur


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and price of Iranian gas to be supplied to Pakistan and India. The latter issue has got seriousl

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 Bangladesh

officials stated in June 2004 that they would be willing to consider a pipeline running acros

Bangladeshi territory from Myanmar to West Bengal in India, provided agreement could be reached o

terms and transit fees. Myanmar reserves are, perhaps, not as substantial as those of Iran and centra

Asia. However the countries proximity to India and the fact that the pipeline will not only brin

Myanmar gas in India and also enable us to monetize Tripura gas and promote industrial and powe

projects in our north eastern and eastern regions have made the proposal attractive. Certain problem

faced while signing the final MOU have forced India to examine the possibility of transporting Myanma

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 geopolitica

and technical issues, it was proposed to import natural gas through LNG route. India's Foreig

Investment Promotion Board (FIPB) approved 12 prospective LNG import terminal projects in the mid

to-late-1990s, but it was never considered likely that all would be built in the near future, as the

combined capacity would have exceeded even the most optimistic demand projections. The India

government froze approvals of new LNG terminals in 2001, and payment problems at the Enron

backed Dabhol Power Plant in Maharashtra led many to question the financial viability of some of th

LNG import projects. Reforms currently being undertaken in the electric power sector may eventuall

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 Ga

de France. Each of the state firms owns a 12.5 percent stake, the Gujarat state government owns a

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 termina

at Dahej began operation in 2004, receiving India's first cargo of LNG on January 30, 2004. The Dahe

terminal had major advantages over some of the other proposed projects, because it is tied in with th


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main state-owned natural gas company, GAIL, and the existing HBJ pipeline network. After severa

delays, Petronet is planning to solicit bids for its second terminal at Kochi in early 2006, with a planne

completion in 2009.

Shell also has begun construction of its LNG import terminal at Hazira in Gujarat, it received its firs

LNG cargo on the 17 th April, 2005 from north west Shell project in Australia .Like the Petronet Dahe

terminal, it is to be linked into existing natural gas pipelines, its first customer was GSPC.She

reportedly has been in discussions with Indian companies about a possible sale of a percentage of it

equity in the terminal.

Enrons Dabhol LNG terminal, which has been idle for the last few years, is now being revived by th

new management, Ratnagiri Gas and Power Pvt.Limited.In this case also it has not been possible t

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 India

companies signed preliminary memorandum of understanding in June 2005 for sales of LNG to suppl

the two Petronet terminals, beginning in 2009 after the completion of the Kochi terminal. Iran agreed t

supply to India 5 mmtpa of LNG at 3.215 dollars per mmbtu FOB. However, i

May 2006 Iran expressed its desire to renegotiate the deal.

TABLE 10

Existing and Proposed LNG Terminals in India (mmtpa)

LNG Terminal LNG Capacity

Existing/under Expansion and Revival

Dahej 5

Dahej expansion 5

Shell Hazira 2.5

Dabhol(revival) 2.5

New Proposal


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Kochi 2.5

Mangalore 5

Kakinada 2.5

TOTAL 25

Source: www.safan.com

OVERSEAS ACQUISITIONS

Another option to enhance energy supply is to encourage indigenous companies to explore in othe

countries thereby increasing equity energy reserves. OVL has nine overseas assets and is activel

seeking more opportunities across the world. With a long term target of acquiring 60 mmtpa of equit

oil and gas overseas by 2025, OVL is currently working towards a goal of 20 mmtpa by 2010. Some o

OVLs investments are in Sakhalin oil fields of Russia (us$1.7 billion), 25% share in GNOP fields o

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

grater Nile project for us $669 million.

A consortium of OVL, IOC, and OIL has also signed a contract with the National Iranian O

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-GAIL

DAEWOO-KOGAS has discov

energy trading {unit 07}

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