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Indian Gas Market
INDIAN GAS MARKET
TABLE OF CONTENTS
1. Fundamentals of Natural Gas
1.1 Introduction
1.2 Natural Gas Processing
2. Global Natural Gas Market
2.1 Overview
2.2 Reserves
2.3 Production
2.4 Consumption
2.5 International Trade
2.6 Economics of Gas Transportation
3. Indian Natural Gas Market
3.1 Overview
3.2 National Exploration License Policy (NELP)
3.3 Reserves & Supply
3.4 LNG Imports
3.5 Natural Gas Demand
3.6 Transportation Infrastructure
3.7 Pricing
3.8 Captive Coal Mining
Indian Gas Market
LIST OF ANNEXURE
Annexure - I: List of Top 10 Countries by Reserve/Production/Consumption
Annexure - II: Indian Demand Projection by Various Agencies
Annexure – III: Institutional Framework of Natural Gas Industry in India
Annexure – IV: Map of Natural Gas Pipeline Network
Annexure – V: Upcoming/Proposed Natural Gas Pipeline Network
Annexure – VI: National Gas Grid
Annexure – VII: Map Showing Pre NELP and NELP Exploration Block under Operation
Annexure – VIII: Cost Competitiveness Comparison of Gas Vs Coal Fired Thermal
Power Plants
Annexure – IX: International Natural Gas Prices Movement
Indian Gas Market
1. Fundamentals of Natural Gas
1.1 Introduction
Natural Gas is a critical fuel in the generation of electric power and is
used in industry as an energy source and/or feedstock for
manufacturing fertilizer, pulp and paper, metals, chemicals, textiles,
plastics and pharmaceuticals, among others. Natural gas is a
combustible mixture of hydrocarbon gases, which in its purest form is
both colorless and odorless. Unlike other fossil fuels, natural gas is clean
burning and emits lower levels of potentially harmful byproducts into
the air. While natural gas is formed primarily of methane, it can also
include ethane, propane, butane and pentane. The composition of
natural gas can vary widely at different locations. The natural gas is
refined to separate individual hydrocarbons present in it, which can be
used separately as different sources of energy.
Methane: Natural gas is stripped down to methane before being used by end consumers. It is the most abundant
component in pure natural gas and is highly combustible. In its pure form the methane is odorless. However an
odorant called Mercaptan is added to it before it is delivered to end users giving it a distinctive “rotten egg” smell.
Once processed from the natural gas, methane is used for generating electricity and sent to homes through pipelines
where it is used for cooking, heating, air conditioning and other activities.
Ethane: It is the next most abundant component of energy found in natural gas. It is a hydrocarbon and a byproduct
of petroleum refining. With a higher heating value than methane, after being isolated from natural gas, it is used to
produce ethylene and polyethylene products. In turn those are used to produce packaging, trash liners, insulation,
wire and other consumer products.
Propane: Propane is an abundant energy source found in natural gas and is processed in gas or liquid form. Often, it
is used for fueling engines, cooking with stoves and for central heating purposes.
Butane: Found in natural gas, butane is not as abundant as other hydrocarbons, but it is still a viable energy source
and can be used for a variety of purposes. Isolated during natural gas processing, butane makes up around 20 percent
of natural gas composition. It is often a component in automobile gas. Refrigeration units and lighters also use a large
amount of butane as fuel.
Indian Gas Market
1.2 Natural Gas Processing
Raw natural gas comes primarily from Crude oil wells, Gas wells and, Condensate wells. Gas that comes from crude
oil wells is typically termed as associated gas, which can exist either as a gas cap above or could have been dissolved
in the crude oil underground formation. Natural gas from gas wells and from condensate wells, in which there is little
or no crude oil, is termed non-associated gas. Gas wells typically produce only raw natural gas, while condensate
wells produce raw natural gas along with other low molecular weight hydrocarbons. Raw natural gas can also come
from methane deposits in the pores of coal seams, and especially in a more concentrated state of adsorption onto
the surface of the coal itself. Such gas is referred to as coalbed gas or coalbed methane. No matter how it is formed,
most produced gas must be treated before the consumer can use it for reasons including meeting sales specification,
pipeline transportation (removal of water etc.), and extraction of liquid by-products (Ethane, Propane and, Butane).
However, the type and extent of natural gas processing depend on the original gas composition and the specifications
of the consumer. The block flow diagram below is a generalized configuration for the processing of raw natural gas
from non-associated gas wells.
Indian Gas Market
2. Global Natural Gas Market
2.1 Overview
Gas has grown from a marginal fuel consumed in regionally disconnected markets to a fuel that is transported across
great distances for consumption in many different economic sectors. Natural gas is now produced and used in 43
countries around the world and has increasingly become the fuel of choice for consumers seeking its relatively low
environment impacts. Presently Natural gas accounts for over 20% of the world’s marketed energy, with
approximately 104 trillion cubic feet (tcf) of natural gas getting consumed globally in 2009. According to a research
performed by Baker Institute, the natural gas share in primary energy consumption is expected to increase to 28% by
2030.
The overall distribution of world natural gas reserves is more concentrated than its production and consumption.
While the top 10 countries (by reserve) controls approximately 77% of the total proved reserves, the top 10 countries
(by consumption) consumes only 57% of the global production. Furthermore, 64% of the global production is done by
top 10 countries (by production). Few of the top consumers like Germany, UK, Japan and Italy etc. are very much
dependent on gas imports, necessitating the transportation of natural gas from major producing countries (especially
Russia). While piped gas continues to dominate global trade in natural gas, nearly 30% of natural gas trade is now
provided by LNG. Further, LNG accounts for nearly 10% of total annual worldwide natural gas consumption. With the
cost of liquefaction (major cost for LNG projects), shipping and storage coming down significantly over the last
decade, the share of LNG in global trade is expected to increase further.
2.2 Reserves
According to ‘BP Statistical Review 2010’, the total
world natural gas reserves at the end of 2009 stood
at 6,620 tcf. The world proved reserves of natural
gas grew by about 78 tcf or 1.2% y/y in 2009 driven
by increases in Russia, Venezuela and Saudi Arabia.
The global Reserve/Production ratio increased to
62.8 years of Production in 2009, as compared to
60.53 in 2008.
While the reserves are spread across globe, Middle
East (41%) and Russian Federation (24%) accounts
for approximately 65% of the total global reserves.
In comparison, Europe & Eurasia, Africa and Asia Pac accounts for 10%, 9% and 8% of the total reserves respectively.
Indian Gas Market
2.3 Production
United States ranked number one in term of
production volume of natural gas in 2009. The
Country produced approximately 21 tcf of
natural gas contributing approximately 20% to
the global production of little over 105 tcf. The
Russian Federation was the second largest
producer with a total production of 18.7 tcf i.e.
18% of world production. Regionally Europe &
Eurasia (Including Russia) topped the list with
32.5% of global production in 2009. North
America and Middle East were second and third
contributing 27.4% and 13.6% of global production respectively.
2.4 Consumption
Consumption of natural gas has been increasing
rapidly making it one of the most important
energy resources in the world. The global
consumption of natural gas has increased by
about 26% over the last decade (CAGR of 2.4%)
reaching close to 104 tcf in 2009. However, the
consumption reported a decline of 2.1% in 2009
as compared to 2008 mostly because of
economic slowdown in major consuming
regions i.e. North America and Europe, which
together consume more than 50% of global natural gas supplies. The Consumption grew at a rapid pace in
Middle East and Asia Pacific over the last decade ended 2009, with natural gas consumption in these
regions increasing at a CAGR of 6.68% and 6.27% respectively.
Indian Gas Market
2.5 International Trade
The main driver of international trade in
natural gas is the mismatch in supply and
demand in various regions. While few gas-
producing countries, such as those in the
Middle East and Africa having excess
production, are able to satisfy all of their
natural gas demand through domestic supply.
Others, such as Japan and South Korea, are
almost entirely reliant on natural gas imports.
Others, including those in Europe and North
America, are able to partially meet natural
gas demand with domestic supply while
supplementing the rest with imports.
According to an estimate by MarketResearch.com, a research firm, Countries in Europe and Eurasia are by far the
leading importers of natural gas and import about 450 billion cubic meters of the fuel, or about 40% of the region’s
natural gas requirements, annually. This region is followed in natural gas imports by the Asia Pacific and North
America regions. Together the three regions account for 95% of global natural gas imports.
The share of international trade remains low essentially due to high transportation costs. As per Cedigaz,
international trade accounted for about 31.7% of world marketed production in 2008, dominated by pipeline gas. A
consequence of low international trade was the creation of regional markets. The main areas were North America,
Western Europe and the former Soviet Union. Other regional markets include Asia-Pacific and Latin America.
However, over the years falling LNG production and
transportation costs have boosted natural gas trade. As of
2008, there were 26 existing liquefaction or export terminals
located in 15 countries around the world. In 2009, Russia
and Yemen added to this list taking up the total to 17
countries. Import terminals are located in 18 countries with
a total of 60 facilities worldwide. In addition, there are 200
liquefaction and regasification projects which are either
proposed or under construction.
Indian Gas Market
There are six significant regional markets that are importing LNG. These are North East Asia, Continental Europe,
North America, the UK, China and India. In northeast Asia, with lack of domestic energy and early adoption of natural
gas, Japan accounts for around 40% of the world’s LNG regasification capacity and is the biggest LNG importer.
Despite the global economic recession in 2008 and 2009, global demand for LNG increased by nearly 22% in volume
terms from 2005 to 2009. North American imports are also expected to more than double from 16 bcm in 2009 to 40
bcm in 2013.
2.6 Economics of Natural Gas Transportation
The transportation of natural gas either by pipeline
or by LNG tankers requires large up-front investment.
Gas transportation costs easily exceed half of the gas
market value and so far only 25% of gas crosses
borders whereas close to 60% of oil does so. The gas
projects are also characterized by long lead times as
more than 10 years may elapse between the
conception of a project and its first revenues.
Indian Gas Market
Source: BP Statistical Review, 2010
Major Natural Gas Trade Movement (Bcm)
Economics of Pipelines: Large-diameter and long distance pipelines imply very high capital investment and require
high-value markets and substantial proven reserves to be economically viable. Capital charges typically make up to
90% of the cost of transmission pipelines. The key determinants of pipeline construction costs are diameter,
operating pressures, distance and terrain. Operating costs vary mainly according to number of compressor stations,
which entails expenses primarily on account of fuel and labor. Globally the investment required to lay a long distance
large diameter line (46’ to 60’) enabling a throughput of about 15 to 30 bcm/year amounts to USD 1 billion to USD 1.5
billion (~INR 4,600 – INR 6,900 Crore @ 1 USD = INR 46) per 1,000 Km. Investments for subsea lines are much higher,
depending on water depths.
Economics of LNG: LNG projects comprising Liquefaction plants, Transport
infrastructure and regasification unit are very much capital intensive. The largest
cost component in the LNG value chain is the liquefaction plant, which consists of
one or more trains, or production units. According to Gas Technology Institute
(GTI), construction of a liquefaction plant that annually produces 390 bcf (8.2
million tons) of LNG could cost anywhere between USD 1.5 to USD 2.0 billion.
Approximately 50% of that amount is for construction and related costs, 30% is
for equipment and, 20% is for bulk materials. In operating the plant, liquefaction
trains account for approximately 50% of the costs of operating an LNG plant,
storage and loading facilities for 24%, utilities 16%, and other facilities account for the remaining 10%. According to
estimates, generic liquefaction costs amount to around USD 1.09 per MMBTU for a two-train, 8 MTPA Greenfield LNG
project and USD 0.97 for an expansion train.
LNG shipping costs are determined by the daily charter rate, which is a function of the price of the ship, the cost of
financing, and operating costs. The costs of building regasification or receiving terminals also show wide variation and
are very site-specific. GTI estimates that terminal costs can range from USD 100 million for a small terminal to USD 2
billion or higher for a state-of-the-art Japanese facility. In the United States, most new terminals are estimated to cost
USD 200 to USD 300 million for a send out capacity from 183 to 365 bcf (3.8 to 7.7 million tons) per year of natural
gas. By far the most expensive items in a terminal are the storage tanks, which can account for one-third to one-half
of the entire cost, depending on the kind of tank. In the United States, the general assumption is that regasification
adds USD 0.30 per MMBTU to the price of the imported LNG.
Economics of CNG: Gas can be transported at high pressure typically from 1,800
psig for rich gas (significant amount of propane, butane etc.) to 3,600 psig for lean Indian Gas Market
gas (mostly methane). Gas at these pressures is termed as Compressed Natural Gas. Compressed natural gas provides
an effective way of transporting gas to short distances (relative to LNG) and is aimed at monetizing offshore reserves
that are unexplored due to lack of transport infrastructure (LNG or Pipeline). Technically CNG is easy to deploy with
lower requirements of facilities and infrastructure. Studies show that for distance up to 2,500 miles, natural gas can
be transported as CNG at prices ranging from $0.93 to $2.23 per MMBTU compared to LNG , which can cost
anywhere from $1.5 to $2.5 MMBTU depending on the distance. At distances above 2,500 miles the cost of using
CNG is higher than LNG because of the disparity in the amount transported using these two technologies.
Indian Gas Market
3. Indian Natural Gas Market
3.1 Overview
Indian primary energy supply is currently dominated by coal (37%), biomass and waste (27%) and oil (26%) while the
share of natural gas is only 10%; it is expected to increase to 28% by 2025. Before 2009, gas demand potential was
estimated to be 20 or 30 bcm higher than actual use as consumption had been constrained by the lack of supply for
over a decade. To address the supply shortfall and encourage private investments in the sector, the GOI in late 1990’s
introduced New Exploration Licensing Policy (NELP), opening Exploration & Production to private and foreign
companies. This has been relatively successful, as of March 2010, a total of 115 discoveries have been made under
exploration done under production sharing contracts between the government and various public, private and
foreign players, of which 70 are gas discoveries. Of theses, commerciality has been established for 19 of them, 42 are
under evaluation, while commerciality is under review for remaining 9.
After stagnating since the early 2000s, the natural gas market in India is evolving rapidly. Over the past decade the
supplies have gone up significantly with commencement of NELP gas production, followed by introduction of term
LNG and finally with the supplies from RIL’s KG D6 gas fields in April 2009. The year 2009 therefore marks a turning
point for the Indian gas market: with new supplies available, Indian gas consumption increased to 59 bcm in FY10,
from 43 bcm in FY09. But challenges remain, illustrated by NELP’s failure to attract the major international oil
companies and the long battle over the allocation and price of KG-D6 gas. The government is now considering
introducing an Open Acreage Licensing Policy (OALP).
Till very recently, the Indian gas sector, like the whole energy sector, was dominated by state-owned companies. Oil
and Natural Gas Corporation (ONGC) and Oil India Ltd (OIL) have dominant upstream positions, while until 2006; Gas
Authority of India Ltd (GAIL) alone had been responsible for pipeline gas transport. However, the recent KG D6
finding by RIL has ousted the ONGC as leading gas producer in the country. In December 2009, RIL became the
country’s biggest natural gas producer with over 50 mmscmd of output, surpassing ONGC’s output of 49.5 mmscmd.
As of April 2010 RIL is producing at the rate of 63-64 mmscmd.
3.2 National Exploration Licensing Policy
India has an estimated sedimentary area of 3.14 million Sqkm
comprising 26 sedimentary basins, out of which 1.35 million Sqkm
area is in deepwater and 1.79 million Sq Km area is in onshore and
shallow offshore. At present 1.06 million Sqkm area is held under
Petroleum Exploration Licenses in 18 basins by national oil
companies Viz ONGC, OIL and Private/JV companies. Before
implementing the NELP in 1999 only 11% of Indian sedimentary
Indian Gas Market
basins were under exploration, which has now increased significantly and only 12% is left unexplored, for remaining
the exploration is under various stages.
New Exploration Licensing Policy (NELP) was formulated by the Government of India, with Directorate General of
Hydrocarbons (DGH) as a nodal agency, during 1997-98 to provide a level playing field to both Public and Private
sector companies in exploration and production of hydrocarbons. The development of E&P sector has been
significantly boosted through this policy of Government of India, which brought major liberalization in the sector and
opened up E&P for private and foreign investment, where 100% Foreign Direct Investment (FDI) is allowed.
Under NELP, which became effective in
February 1999, acreages are offered to the
participating companies through the
process of open competitive bidding. The
first round of offer of blocks was in the
year 1999 and second to eight rounds
were in the years 2000, 2002, 2003, 2005,
2006, 2008 and 2009 respectively. So far
326 exploration blocks have been awarded under NELP. The Ninth round under NELP has already kicked off in
October 2010.
Oil and Oil-Equivalent Gas (O+OEG) in place reserve accretion under NELP is approximately 600 million metric tons.
An investment of USD 11.97 billion has already been made under NELP and currently more than 70 companies are
working in India. At present there are 234 contracts under operations out of which there are 16 pre-NELP blocks, 168
NELP blocks, 27 fields and 23 Coal Bed Methane (CBM) blocks.
Key Features of NELP
Up to 100% participation by foreign companies
No mandatory state participation
No carried interest by National Oil Companies
No custom duty on imports require for petroleum operations
Biddable cost recovery limit: up to 100%
Option to amortize exploration and drilling expenses over a period of 10 years from first commercial
production.
Royalty Rates: Crude Oil – 12.5% (On land areas), 10% (Shallow water); Natural Gas - 10% (On land areas),
10% (Shallow water). For deepwater offshore royalty is payable for both natural gas and crude oil at the rate
of 5% for first seven years of commercial production and thereafter at the rate of 10%.
Indian Gas Market
Onshore / Shalow Water
Offshore Total
NELP - I 48 27 17 7 24 12 11
NELP - II 25 23 15 8 23 17 5
NELP - III 27 23 14 9 23 1 22
NELP - IV 24 21 10 10 20 1 19
NELP - V 20 20 14 6 20 0 20
NELP - VI 55 52 31 21 52 0 52
NELP - VII 57 44 NA NA 41 0 41
NELP - VIII 70 36 NA NA 32 0 32Source: Directorate General of Hydrocarbon
Exploration Blocks Awarded under NELPBlocks for which Bids Received
Blocks Offered
NELP Round
Blocks Relinquished
Blocks Operational
Blocks Awarded
3.3 Natural Gas Reserves & Supply
Proven and indicated reserves of natural gas in
India were 1,437 bcm as of April 1, 2010 as
compared to 1,074 bcm as of 1 April 2009, an
increase of 33.8%. The majority of these reserves
(829 bcm) represent onshore gas reserves, while
the remaining 608 bcm is offshore reserves,
according to the Ministry of Petroleum and Natural
Gas. The Country produced 47.51 bcm of natural
gas in FY10, an increase of 44.6% over 32.85 bcm
produced in FY09. More than 81% of the
production in FY10 came from offshore fields.
While the productions from ONGC’s fields remain
mostly stable it was private players who propelled
the production growth. The contribution of private
players in country’s production almost doubled to
46% in FY10 from 25% in FY09. Private players/JVs
produced a total 21.99 bcm in FY10.
Regionally, fields located in Gujarat, Assam,
Tamilnadu and Andhra Pradesh are major source
of onshore gas together accounting for about
16.5% of the total gas produced and 90% o f the
total onshore gas production in FY10. The
remaining is produced in fields located in
Rajasthan, Tripura and Arunachal Pradesh. For
offshore gas, Bombay High still remains a key producer accounting for more than 45% of total offshore and 36% of
the total gas production of the country. The field produced approximately 17.5 bcm of natural gas in FY10.
Indian Gas Market
Source: MoPNG
Source: MoPNG
Source: MoPNG
The major source of gas in the foreseeable future
is likely to come from the eastern offshore region,
particularly Krishna-Godavari basin. The
established gas reserves in the region are around
373.74 bcm. The majority (351.15 bcm) of this is
accounted for by the KG basin which has
established gas reserves of 35 1.15 bcm. The
eastern offshore region is spread over an area of
299,000 sqkm, with resources of about 48 billion
barrels of oil and oil equivalent gas. Of this, the gas
resources are around 153 tcf with gross initial in-place reserves at 16.38 tcf. Most of the gas production from the
region is likely to come from the KG basin, Mahanadi Basin and the Cauvery basin.
A total of 72 blocks have been awarded in the
region of which 28, 23 and 19 were in KG, Cauvery
and Mahanadi respectively. According to
estimates from Directorate General of
Hydrocarbons, the peak production from East-
Coast is expected to be over 120 mmscmd during
2015-2020. According to estimates by MoPNG the
supply of natural gas is expected to reach 73.8 bcm
by 2011-12.
3.4 LNG Imports
India started importing natural gas in the form of
LNG from 2004-05 with the commissioning of its
first LNG terminal at Dahej. Currently the total
import capacity of the country’s two LNG terminal
is 13.5 MTPA (18 bcm). In 2009-10, India imported
12.3 bcm of LNG from Qatar, Australia, Trinidad
and Russia. Until 2009, India only had one long
term LNG contract signed to supply the Dahej
terminal for 5 MTPA (6.7 Bcm), as the second
terminal in Hazira operates on the merchant
model. The long term contract from 2004 with Qatar’s RasGas was based on fixed price of USD 2.53/MMBTU FOB for
Indian Gas Market
Sector Firm Allocation (Mmcm/d)
Interruptible allocation (Mmcm/d)
Power Plants 31.0 12.0Fertilizers 15.0 0.0LPG and Petrochemicals 3.0 0.0City Gas 5.0 2.0Reliance Petroleum 1.9 0.0Oil Companies 6.0 6.0Captive Power 0.0 16.0Total 61.9 36.0Source: IEA
Allocation of KG-D6 Gas
5 MTPA for the first five years. Since January 2009, this price increased to USD 3.12/MMBTU. Volumes under this
contract has also risen to 7.5 MTPA (10 Bcm) in Q4 2009, due to extension of the terminal’s capacity. In 2010, Qatar
announced that these supplies will be boosted to 11.5 MTPA by 2014. This could start as soon as 2011 with an
additional 1 MTPA, increasing to 2.5 MTPA by 2012 and 4 MTPA by 2014.
On 8 May 2009 Petronet LNG finalized talks concerning the purchase of 1.5 MTPA of LNG for 20 years from
ExxonMobil’s planned output from Goregon LNG plant in Australia, expected to start operating in 2014. This puts
total contracted LNG supplies to 18 bcm as of 2014, 2/3rd of the LNG capacity that will be online that time. Australian
supplies will be sent to Kochi terminal which is expected to begin operation in 2012.
3.5 Natural Gas Demand
According to the MoPNG, gas use in India amounted to 47.25
bcm in FY10, up 44% from 32.73 bcm in FY09. While 61% of
the total consumption amounted to energy use, 39% was
used for non-energy purposes. The demand for natural gas
comes from variety of sectors including power, fertilizer,
refining & petro chemicals, Glass & Ceramics, Metals &
Mining etc. However, power and fertilizer are the key
consumers and expected to remain so.
Before the start of KG-D6 in April 2009, consumption was
supply constrained and unmet demand of natural gas in 2007
was estimated at about 35 bcm. Total demand for FY09 was
estimated at 72 bcm, 40 bcm higher than actual consumption,
while demand for FY10 was to reach 81 bcm as compared to
actual use of approximately 47.25 bcm. Unmet demand rests
in the power sector and the industrial sector (around 40% of
unmet demand each) with fertilizer production accounting for
the rest.
Demand from Power Generation
Gas uses by power sector depends on three factors- Electricity Demand, Gas Availability and, Competitiveness of gas
fired plants versus coal fired plants. According to CEA, the current installed capacity as of December 2010 amounts
169.80 GW, with gas representing 10.27% (17.45 GW) versus 54% (92.4 GW) of coal. The IEA estimates that India’s
generation capacity will increase almost fourfold between 2009 and 2030 to reach 571 GW with gas fired capacity
Indian Gas Market
increasing to 299 Twh by 2030. According to estimates by working group on XIth plan, the gas demand from power
generation will reach 126.57 mmscmd by FY12.
Gas has benefited from the shortage of domestic
coal, which resulted in gas to be used as base load
even with non-APM gas. Pre KG-D6 find gas
availability was a constant problem and many gas
fired plant were either using alternative fuel such
as naphtha or not running at all. The CEA
estimated that the shortfall of gas to the
generation sector over the period 2000-08 was
between 6.6 to 10.2 bcm. With KG-D6 coming
online, the gas fired plant load factor has increased from 57% in January 2009 to 77% in April 2010. PLF in FY10 was
around 10% higher than the same period one year earlier.
While electricity demand and gas availability will affect gas usage in the sector, it is the competitiveness of gas versus
coal that will have highest impact on gas demand. In most cases it will be difficult for gas to compete against
domestic gas; especially if coal fired plant is located near coal mine. However, given the geographical distribution of
coal reserves and power plants, coal needs to be transported on long distances, incurring additional cost.
Furthermore continuous tight supply conditions for coal versus easy availability of gas can also favor increased gas
usage.
Demand from Fertilizer Sector
The fertilizer industry uses natural gas as a primary
feedstock instead of the more expensive naphtha
or fuel oil. In FY09 the demand from this sector
represented 9 bcm, or approximately 20% of the
total demand. Over the past year, several fertilizer
units have been switching to gas as new supplies
from KG-D6 have become available. According to
the pricing policy of urea announced in January
2004, all the new and expansion projects for urea
have to be gas-based, and all the existing urea units have to convert to natural gas under stage III of the policy which
commenced from November 2006. The government policy allows for urea plants using naphtha/Fuel Oil to convert to
natural gas by 2012 (earlier deadline March 2010). Among the naphtha based fertilizer plants that will convert to
natural gas by 2012 additional demand of 6.5 mmscmd is estimated. An additional demand of 6 mmscmd is estimated
from the conversion of furnace oil based plants. Overall, as per GoI estimates, the total requirement of gas at the
Indian Gas Market
end of the XIth plan period by fertilizer sector is
estimated at about 76 mmscmd, an increase of
150% from the current 39 mmscmd.
IEA estimates total Indian gas demand to reach 94
bcm by 2020 and 132 bcm by 2030 growing at
5.4% per annum over 2007-30. (Refer Annexure-II
to see Natural Gas Demand estimates by various
agencies)
3.6 Transportation Infrastructure
Pipeline Network
The present natural gas transportation
infrastructure comprises of around 11,000 km
pipelines with capacity of 270 mmsmcd. The
utilization for this was around 62% in 2008-09. The
low utilization was due to commissioning of new
pipelines, which could not be properly utilized until
production from KG-D6 ramped up. The current
pipeline infrastructure is comprised of only two trunk pipelines: the Hazira-Bijaipur-Jagdishpur (HBJ) network pipeline
that connects the western coast to northern India, and the recently-commissioned Kakinada-Bharuch pipeline by
Reliance Gas Transmission India (RGTIL). Of the total pipeline length, 7,000 KM of network belongs to GAIL, 2,000 to
Gujarat State Petronet Ltd (GSPL), 1,400 KM to RGTIL, and 500 KM to Assam Gas Company Ltd and Indian Oil Ltd.
Most of the current network is concentrated in western and north western India. Several new pipelines are under
various stages of development and implementation of these is set to create a national gas grid with around 16,500
KM of pipeline network by 2013 that would cover most of the country.
Hazira-Bijaipur-Jagdishpur (HBJ): It is the largest cross country gas transmission system with a length of around
3,100 KM (including 387 KM Dadri-Vijapur Gas Rehabilitation and Expansion Projects (GREP) pipeline). The pipeline
network runs through Gujarat, Madhya Pradesh, Rajasthan, Uttar Pradesh, Haryana and Delhi. The pipeline has a
capacity of over 33 mmscmd. The transportation charges along the HVJ pipeline are Rs 1,150 per thousand cubic
meters (mcm) of gas, linked to the calorific value of 8,500 kcal/mcm.
The East-West Pipeline (EWPL) of RGTIL: Commissioned in April 2009, EWPL has a capacity of 80 mmscmd which is
also the peak production expected from KG-D6 block. The pipeline connects to GAIL’s pipeline network at three
locations at Oduru in KG Basin, Mhaskal with Dahej Uran Pipeline – Dabhol Panvel Pipeline network in Maharashtra,
and at Ankot with HBJ-DVPL-GREP network in Gujarat.
Indian Gas Market
Upcoming Pipeline Network
- GAIL has already been authorized by the MoPNG to undertake new pipelines of about 5,500 KM, which are
scheduled to be operational in phases by 2013. (See Annexure –V for details)
- RGTIL too has received authorization for pipelines of about 2,800 km in length, which are scheduled to be
completed by 2012-13. In addition to this RGTIL propose to construct additional network of about 845 KM.
(Refer Annexure-V for details)
LNG Terminals
For LNG import infrastructure, currently there are two LNG terminals at Dahej and Hazira in Gujarat which are already
operational with a total existing capacity of 13.6 MTPA. Dahej terminal is owned by Petronet LNG Ltd. with a total
capacity of 10 MTPA, while Shell Hazira Private Ltd is of 3.6 MTPA. Both these terminals are located on the western
coast of Gujarat. The third terminal in Dabhol with a capacity of 5 MTPA is under commissioning. The work is
underway for another terminal at Kochi with a capacity of 2.5 MTPA. With commissioning of these terminals, the
total LNG handling capacity of the country is estimated to reach a total of 20 MTPA by 2011-12.
The operators of both the existing LNG terminals have plans to further increase their capacities. Dahej to 12.5 MTPA
and then further to 15 MTPA, while Shell plan to increase its capacity to 5 MTPA.
3.7 Pricing
The natural gas pricing scenario in India is complex and heterogeneous in nature. There are wide varieties of gas price
in the country. At present, there are broadly two pricing regimes for gas in the country - gas priced under APM and
non-APM or free market gas. The price of APM gas is set by the Government. As regards non- APM/free market gas,
this could also be broadly divided into two categories, namely, domestically produced gas from JV fields and imported
LNG.
APM Gas Pricing
APM gas refers to gas produced by entities awarded gas fields prior to the Production Sharing Contract (PSC) regime.
The prices of gas from these fields are administered by GoI. The Government raised the consumer price from INR
2,800 /mscm to INR 3,200 /mscm with effective from July 1st 2005 for the following categories of consumers. It was
also decided that all the APM gas will be supplied to only these categories.
Power sector consumers
Fertilizers sector consumers
Consumers covered under court orders
Consumers having allocations of less than 0.05 mmscmd
Indian Gas Market
GoI also decided that the price of gas
supplied to small consumers and transport
sector (CNG) would be increased over the
next 3 to 5 years to the level of the market
price. With effect from May 6th 2005, the
APM gas price to small consumers and CNG
sector has been increased by 20%, to bring it
to INR 3840 /mscm. The price of natural gas for customers in the North-East has been kept at 60% of the price in the
rest of the country. Accordingly, the price for power and fertilizers sector in the North-East is INR 1,920/mscm and
that for court-mandated and small scale consumers in the region is INR 2,304/mscm. However, in a move to
deregulate the gas prices, APM gas prices were revised upward by 113% in May 2010 to bring them at par with Non-
APM gas prices from INR 3,200 /mscm to INR 6,818 /mscm or USD 4.2 /MMBTU.
Non-APM (NELP Gas Pricing)
As regards the gas from NELP fields, the Government constituted an Empowered Group of Ministers to consider
issues relating to pricing of natural gas, produced under the NELP regime. The following price basis/formula for the
purpose of valuation of natural gas has been approved by the Government in case of KG-D6 Block of RIL/Niko.
Selling price ($/MMBTU) = 2.5 + (CP-25) X 0.15, where CP=crude price in $/bbl, with cap of CP= $60/bbl.
The price basis/formula comes to US$4.2/MMBTU for crude price greater or equal to US $60/barrel. It was decided
that price discovery process on arm's length basis will be adopted in the future NELP contracts, only after the
approval of the price basis/formula by the Government. It was also decided that the price discovered through this
process would be uniformly applicable to all the sectors.
Indian Gas Market
Annexure – I: List of Top 10 Countries by Reserve/Production/Consumption
Indian Gas Market
Proved ReservesShare of
Total(Tcf) %
1 Russian Federation 1,567.1 23.67% 23.67%
2 Iran 1,045.7 15.79% 39.46%
3 Qatar 895.8 13.53% 52.99%
4 Turkmenistan 286.2 4.32% 57.31%
5 Saudi Arabia 279.7 4.22% 61.54%
6 US 244.7 3.70% 65.23%
7 United Arab Emirates 227.1 3.43% 68.66%
8 Venezuela 200.1 3.02% 71.68%
9 Nigeria 185.4 2.80% 74.48%
10 Algeria 159.1 2.40% 76.89%
WORLD TOTAL 6,621.2
Source: BP Statistical Review, 2010
Top 10 Countries Based On Natural Gas Reserves (in Tcf)
Rank by Reserves
CountryCummulative
Share
Production(Tcf)
1 US 20.95 19.87% 19.87%
2 Russian Federation 18.63 17.66% 37.53%
3 Canada 5.70 5.40% 42.93%
4 Iran 4.63 4.39% 47.32%
5 Norway 3.65 3.46% 50.79%
6 Qatar 3.15 2.99% 53.78%
7 China 3.01 2.85% 56.63%
8 Algeria 2.88 2.73% 59.35%
9 Saudi Arabia 2.74 2.59% 61.95%
10 Indonesia 2.54 2.41% 64.35%
WORLD TOTAL 105.48
Source: BP Statistical Review, 2010
Top 10 Countries Based On Natural Gas Production (in Tcf)
Share of Total (%)
Rank by Production
CountryCummulative
Share (%)
Indian Gas Market
Consumption Share of (Tcf) %
1 US 22.83 21.99% 21.99%
2 Russian Federation 13.76 13.25% 35.24%
3 Iran 4.65 4.48% 39.72%
4 Canada 3.34 3.22% 42.94%
5 China 3.13 3.02% 45.96%
6 Japan 3.09 2.97% 48.93%
7 UK 3.06 2.94% 51.88%
8 Germany 2.75 2.65% 54.53%
9 Saudi Arabia 2.74 2.63% 57.16%
9 Italy 2.53 2.44% 56.96%
WORLD TOTAL 103.84
Source: BP Statistical Review, 2010
Top 10 Countries Based On Natural Gas Consumption (in Tcf)
Rank by Consumption
CountryCummulative
Share (%)
Annexure – II: Indian Demand Projections by Various Agencies
Annexure – III: Institutional Framework for Natural Gas Industry in India Indian Gas Market
Agency (Year)
IEA (2004)
IHV-2025 (2000)
P & E Division (2003-04)
Reference Case
High Case Low Case BAU BCS BAU HOG
Base Year2001 (62)
2001 (62)
2001 (62)
2000 (67)
1999-2000 (110)
2001-02 (81)
2004-05 74 77 74 91 195 89 87 98 93 95
2009-10 93 101 93 140 277 115 111 134 145 164
2014-15 124 132 109 189 329 149 142 183 226 285
2019-20 155 171 132 228 358 194 177 249 356 493
2024-25 195 225 155 259 391 258 226 326 488 738
2029-30 295 430 667 1111
EIA - Energy Information Administration, USA BAU - Business as Usual
IEA - International Energy Agency BCS - Best Case Scenario
IHV - India Hydro Carbon Vision -2025 HOG - High Output Growth
IRADe - Integrated Research & Action for Development P & E - Power & Energy Division
Demand Projections under Different Scenarios by Various Agencies (MMSCMD)
2003-04 (85)
EIA (2004)
India Vision-2020 (2002)
1997 (59)
IRADe & PWC
Indian Gas Market
S No. Institution Function Remarks
1 Ministry of Petroleum and Natural GasRegulation of exploration, production,development, allocation and pricing of gas.
Apex policy making body.
2 Directorate General of Hydrocarbons
Regulates upstream industry and is involvedin issue of licences & Production SharingContracts (PSC) with both the state andprivately owned enterprises.
Estabilished in 1993 toensure correct reservoirmanagement.
3 Oil Industry Safety Directorate
Formulates and Coordinatesimplementation of series of self regulatorymeasures aimed at enhancing safety in oil &gas industry.
Technical Directorate underMoPNG.
4 Petroleum & Natural Gas Regulatory BoardRegulates downstream industry includingtransportation, distribution and marketingof natural gas.
Ensuring fair trade andcompetition, laying downsafety standards etc.
5 Petroleum India InternationalProvides Technological & Managerialexpertise to companies abroad.
Consortium of IOCL, HPCL,OIL, IPCL and BRPLestablished in 1986.
Institutional Framework for Natural Gas Industry in India
Source: GAIL
Annexure – IV: Map of Natural Gas Pipeline Network
Indian Gas Market
Annexure – V: Upcoming/Proposed Natural Gas Pipeline Network
Indian Gas Market
Upgradation of DVPL pipelines 78 610 5,0002009 (Phase I)2011 (Phae II)
Upgradation of GREP pipelines 20 to 62 505 2,0002009 (Phase I)2011 (Phae II)
Dadri-Bawana-Nangal Pipeline (Passing through UP, Delhi, Haryana & Punjab)
31 610 2,5002009 (up to Bawana)2011 (up to Nangal)
Chainsa-Gurgaon-Jhajjar-Hissar Pipeline (Passing through Haryana & Rajasthan)
25 310 1,0002009 (Up to Chainsa)2011 (up to Hissar)
Jagdishpur - Haldia Pipeline (Passing through West Bengal, Jharkhand, Bihar & UP)
12 876 3,300 2011
Dhabol-Bangalore Pipeline (Passing through Maharashtra & Karnatakat)
12 730 2,500 2011
Kochi-Kanjirkkod-Mangalore/Bangalore 12 840 2,500 2012
Source: GAIL
Additional Pipeline Network Under Development by GAILLength (KM)
Capacity (MMSCMD)
Estimated Cost (Rs Crores)
Completion Year/Status
Pipeline Distance (KM)Kakinada - Haldia pipeline 1,100
Kakinada - Chennai pipeline 445
Chennai - Bangalore - Mangalore pipeline 600
Chennai - Tuticorin pipeline 670Source: IIR Gas Report, 2010
New Pipeline Network by RGTIL
Annexure – VI: National Gas Grid
Indian Gas Market
Pipeline Segment Status Length (Km)
Hazira-Vijaipur-Jagdishpur Operational 3,100
Dahej - Vijaipur Operational 610
Dahej - Uran Operational 474
Dabhol - Panvel Operational 322
Vijaipur-Kota-Mathania Under Development 565
Dadri-Bawana-Nangal Under Development 610
Dabhol - Bangalore Under Development 730
Jagdishpur - Haldia Operational 876
Chainsa-Gurgaon-Jhajjar-Hisar Under Development 310
Vijapur-Auraiya-Jagdishpur upgradation Operational 571
Kochi-Kanjjirkkod-Mangalore/Bangalore Under Development 840
East-West Operational 1,400
Kakinada - Chennai Proposed 580
Kakinada - Haldia Proposed 1,037
Ahmedabad - Rajkot- Jamnagar Proposed 685
Bangalore - Coimbatore - Kochi Under Development 440
Chennai - Tuticorin Proposed 550
Hyderabad - Vijaipur Under Development 1,100
Myanmar - India border to Gaya Proposed 1,573
Total 16,373
Operational 7,353 45%
Under Development 4,595 28%
Proposed 4,425 27%
Source: India Infrastructure Research, 2010
National Gas Grid
Annexure – VII: Map of Pre NELP and NELP Exploration Block under Operation
Annexure- VIII: Cost Competitiveness Comparison of Gas Vs Coal Fired Thermal Power Plants
APPROACH-1: Comparison based on short run marginal costs (SRMC) for existing plants.
Indian Gas Market
The analysis is based on 250 MW gas fired plants, with 46% efficiency which is relatively higher as compared to 32-37% of coal fired plants (old) of this size.
Assuming the plant receives APM gas at USD 1.8/MMBTU. However it has now been revised to USD 4.2/MMBTU to the level of KG-D6 gas.
A transportation cost depending upon the location of the plant need to be added. Following five cases has been assumed:
1. APM gas (old prices) transported through the HVJ line
2. KG-D6 gas consumed in eastern region
3. KG-D6 gas consumed in the north-western region
4. LNG import from Qatar under a long term contract and consumed in north western region
5. LNG spot purchase at landed prices of USD 8/MMBTU and consumed in north western region
Gas fired plants have been compared to four coal-fired plants, three using domestic coal and one using imported coal. Plants using domestic coal have 32% efficiency versus 37% for imported coal. Domestic coal is based on Grade E coal prices and is burned either at the mine mouth, or transported 700 KM or 1,500 km. The prices for imported coal are assumed at USD 90 / ton.
As evident from the above comparison the cheapest option is the coal-fired plant using domestic coal at pit-head.
APPROACH-2: Comparison based on cost of generation for new plants.
Indian Gas Market
Source: IEA
SRMC of existing coal-fired plants versus gas fired plants
The price assumptions remain same as above except the price of APM gas where the revised value has been considered (USD 4.2 / MMBTU).
Discount rate for all the plants have been assumed at 10%
For new power plants efficiency has been assumed at 46% and 57% for coal fired and gas fired plants respectively.
Annexure- IX: International Natural Gas Price Movement Indian Gas Market
Source: IEA
Cost of Generation for new coal-fired plants versus gas fired plants
Source: BP Statistical Review, 2010
Indian Gas Market
