Gas Pooling Report

7/30/2019 Gas Pooling Report

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Report of the Inter-Ministerial

Committee on Policy for Pooling of

Natural Gas Prices and Pool Operating

Guidelines

August 2011

Planning CommissionGovernment of India

New Delhi


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TABLEOFCONTENTS

Executive Summary .................................................................................................................. 1

Chapter I: Analysis & Recommendations................................................................................. 6

1.0 Background and Problem......................................................................................... 6

2.0 Proposed Scheme of Preferential Allocation ........................................................... 9

3.0 Impact of the Future Increase in Domestic Gas Output ......................................... 15

4.0 Previous Commitments .......................................................................................... 17

5.0 Isolated Gas Fields ................................................................................................. 18

6.0 Pipe Line Tariff...................................................................................................... 18

7.0 Pooling/Preferential Allotment .............................................................................. 19

8.0 Contract and Swap ................................................................................................. 20

9.0 Taxes on Natural Gas/LNG.................................................................................... 21

10.0 Domestic Natural Gas Prices ................................................................................. 22

Chapter II: Energy Consumption Trends. ..27

12.0 Primary Energy of which Oil & Gas...................................................................... 27

13.0 Growth in Consumption Natural Gas.................................................................. 27

14.0 Natural Gas pipelines and LNG ............................................................................. 28

15.0 Reserves and Producing Countries......................................................................... 28

16.0 Liquefied Natural Gas............................................................................................ 28

17.0 Shale and Other Unconventional Gases................................................................. 29

18.0 Impact of gas prices ............................................................................................... 29

19.0 Likely Trajectory of Global Gas Demand.............................................................. 30

20.0 Trans-National Transportation Is Likely to Rise ................................................... 30

21.0 Evolution of LNG Markets .................................................................................... 31

22.0 Gas Price Setting Mechanism Differ Across Regions ........................................... 31

23.0 Some Features of the LNG market......................................................................... 32

Chapter III:Indian Gas Markets Demand & Supply Side.................................................... 33

24.0 Introduction............................................................................................................ 33

25.0 Domestic Demand for Natural Gas ........................................................................ 34

26.0 Future Gas Sourcing............................................................................................... 39


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Chapter IV:Non-conventional Natural Gas Sources .............................................................. 43

27.0 Coal Bed Methane (CBM) ..................................................................................... 43

28.0 Shale Gas ............................................................................................................... 44

Chapter V :Liquefied Natural Gas (LNG) .............................................................................. 45

29.0 LNG Terminals in India......................................................................................... 45

30.0 Gas Pricing: Status of Price of Gas/LNG from Different Sources......................... 48

31.0 Price of Long-term LNG Imports .......................................................................... 50

32.0 Gas Pipeline Infrastructure in India ....................................................................... 51

33.0 National Gas Grid .................................................................................................. 54

34.0 The Rationale for Postal Tariff .............................................................................. 54

35.0 Location Economics and Efficiency ...................................................................... 56

Annex-I: Extracts from the Study Conducted by Mercados.................................................. 58

Suggested Mechanism for Gas Price Poling by M/s Mercados .............................................. 58

Recommendations.................................................................................................................... 60

Creation of an Overarching Pool ............................................................................................ 63

Concern over Price Discovery ................................................................................................ 63

Appendix 1 Constitution of interministrial Commitee ........................................................ 66

Appendix-2 Letter from JS (TRU), Ministry of Finance.68


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LIST OF TABLES

Table 1.1 Natural Gas Production and Imports ...................................................................... 8

Table 1.2 Sectoral Consumption of Natural Gas including R-LNG..................................... 11Table 1.3 Price Comparison of liquid Automotive Fuels, CNG and Gas from R-LNG....... 11

Table 1.4 Utilization of Domestic Natural Gas .................................................................... 13

Table 1.5 Utilization of Domestic Natural Gas .................................................................... 14

Table 1.6 With Incremental Domestic Natural Gas Going Entirely to Power Sector .......... 16

Table 1.7 Status of Supply and Price.................................................................................... 23

Table 3.1 Consumption of Natural Gas by Sector................................................................ 34

Table 3.2 Optimistic Projections of Output of Natural Gas ................................................. 40

Table 3.3 Projected Availability of Domestic Gas............................................................... 41

Table 5.1 LNG Terminals..................................................................................................... 46

Table 5.2 Current Gas prices prevailing in select gas importing countries .......................... 48

Table 5.3 - Price & volume of Gas from domestic sources of supplies .................................. 48

Table 5.4 Customer wise and Producer wise Gas Prices as prevailing in India................... 49

Table 5.5 Natural Gas infrastructure in India....................................................................... 51

Table 5.6 Regional Imbalance in Natural Gas Infrastructure ............................................... 51

Table 5.7 Pipelines to GAIL about 5,500 kms ..................................................................... 52

Table 5.8 Pipeline to RGTIL around 2800 Kms .................................................................. 52

Table 5.9 Pipeline through bidding process ......................................................................... 53

Table 5.10 Summary of Pipeline Status ............................................................................... 53

Table 5.11 Additional Pipelines ........................................................................................... 53

Table 5.12 Zonal Tariff Order.............................................................................................. 55

LIST OF CHARTSChart 1 Pricing Mechanism Worldwide ............................................................................... 32

Chart 2 Composition of Indias Energy Basket.................................................................... 33

Chart 3 Projected net gas production from domestic sources, 2015..................................... 41

Chart 4 Gap between Demand and Supply - Projection for next decade ............................. 47

Chart 5 Affordability of LNG by different sectors............................................................... 50


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EXECUTIVE SUMMARY

0.i. Presently domestic gas demand exceeds domestic supply. In future years,the incremental domestic demand will significantly exceed potential

incremental domestic supply. This will mean that the import content of

total natural gas consumption will have to increase.

0.ii. There is a large price differential today between domestic and importedgas. Domestic gas is priced at $4.2 to $5.5 per mmbtu + pipeline charges +

taxes. In contrast R-LNG spot prices are $10 to $14 per mmbtu + pipeline

charges + taxes.

0.iii. Higher prices are a burden to everybody. Nobody voluntarily chooses topay the higher price. However, there are differences in policy priorities, as

well as great differences in the paying capacity of different users,

specifically in light of regulatory restrictions on certain classes of users to

freely set their selling prices.

0.iv. The priorities and regulatory burden are concentrated in the fertilizer andpower sectors.

0.v. The recommendations of this report assign priority, following the existingpolicy of Government.

0.vi. The Committee does not recommend pooling mechanism for natural gas atthe overall level, nor does it recommend a price pooling on sectoral basis,

except where that may be found to be the best workable option.

0.vii. The Committee has opted for preferential allotment on a scheme ofpriority as a basis for allocating the scarce resource namely, domestically

produced natural gas in this case across users.

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0.viii. The Committee visualizes the internal consumption in oil/gas fields(injection, turbines, flaring), pipeline internal consumption and LPG/C2

C3 extraction as a clear necessity.

0.ix. The balance that is left after this is what is available for allocation.0.x. Fertilizer and power sectors have been given first priority for domestic gas.

But it is recognized that even they will have to consume some amount of

R-LNG. The priority on domestic gas being given to the power sector

flows from the policy of the Ministry of Power to require gas based power

plants to have a PPA for 85 per cent of their generation.

0.xi. The projections in this report visualize that of the fertilizer sectors totalconsumption, RLNG will amount for 2122 percent, while that for the

power sector the share of R-LNG will be around 2527 per cent based on

the existing capacity and new plants already under construction. The latter

projections may change depending on the level of domestic gas

production.

0.xii. For CGD/CNG and other Court mandated customers, the Committeerecommends that a certain amount of domestic gas be set aside for their

usage. These quantities are 6 mmscmd for CGD/CNG and 1 mmscmd for

other Court mandated customers. Presently the former is drawing 5.3

mmscmd and the latter 0.9 mmscmd. Thus the allocation procedure of the

Committee does not reduce their current access to domestic gas, but

requires that their additional needs will have to be met from imports.

0.xiii. Non-priority sectors presently consume about 18.4 mmscmd of domesticgas and an amount of 5 mmscmd is being set aside for these users. Their

balance needs at both current levels and their incremental needs have to be

met from imported R-LNG.

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0.xiv. These (non-priority) users operate in a market environment where theiroutput prices are market driven with no regulatory burden and hence they

should be able to pass on the higher costs of gas feedstock.

0.xv. In regard of the RLNG needs, the users should have a choice of eithersourcing their own supply of LNG or depending on their present suppliers

to give them gas at blended domestic and RLNG price.

0.xvi. Large users may opt to choose to source their own RLNG and this willhelp develop a competitive market for RLNG.

0.xvii. By making such a large segment of users opt for RLNG, a competitivemarket will be created to serve the interests of this sector. This will ensure

that inefficient LNG pricing cannot prevail. It is also believed that by

exposing this class of users to RLNG and giving them the option of

sourcing their own RLNG, the scope for use of RLNG will be greatly

enhanced.

0.xviii. Smaller users (and some larger users also) who may not be in a position tosource their own R-LNG will have to obtain a blended price from their

suppliers. The suppliers can arrive at a blended price depending on their

own costs of supply and should do so in a fair and equitable fashion.

0.xix. In future years, there will be an increase in domestic gas production butthere is no certainty as to what extent this increase will be. The Committee

has looked at four different scenarios and feels that the most likely one

from a fairly conservative point of view is Scenario# 2 which envisagesthat total (gross) domestic gas output will increase from the present level

of 132.5 mmscmd to around 199 mmscmd by 2016/17 that is, a

compounded annual rate of output growth of about 8.5 per cent..

0.xx. At the level of production of 199 mmscmd in 2016/17, the fertilizer sectorwould need to source 22 per cent of their requirement from RLNG while

the power sector, on the basis of existing schedule of gas based power

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plants coming up, will need to source 27 per cent of their requirement from

RLNG by 2016/17.

0.xxi. All other users, including CGD/CNG and non-priority industries, wouldhave to source the bulk of their requirement from RLNG. In 2011/12,

about 73 per cent of their total requirement would have to come from R

LNG and this proportion is likely to rise to little over 80 per cent by

2016/17 depending on the growth of demand from the sectors.

0.xxii. Total RLNG imports are likely to rise from about 46 mmscmd presentlyto about 103 mmscmd by 2016/17.

0.xxiii. The Ministry of Power would like to emphasize that taking R-LNGbeyond 25 per cent will be difficult keeping in mind the economics of the

electricity distribution business. They also would like to get firm

commitments on domestic gas supply and a clear idea of future price. The

Committee however felt that it is not in a position to take a view on firm

domestic gas supply and future prices.

0.xxiv. As stated previously, no explicit pooling for gas price is being prescribed.However, the preferential allocation will have to be done by the concerned

administrative ministries. In the Department of Fertilizers, FICC is

institutionally capable of discharging the task. In the case of the Ministry

of Power, the requirements will have to be overseen by the Ministry of

Petroleum & Natural Gas. It is understood that in the allocation of

domestic natural gas, cost and other efficiency criteria will inform the

administrative decision.

0.xxv. The other preferential allocations of 6 mmscmd to CGD/CNG, of 1mmscmd to other Court mandated customers and of 5 mmscmd to non-

priority users will have to be distributed in a reasonable and fair fashion by

the Ministry of Petroleum & Natural Gas.

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0.xxvi. It is recommended that the pipeline tariff which is presently being set on acost/bid-based Zonal tariff basis should be modified to the extent that the

outlier tariffs (for small off-takes) should not be more than 50 per cent of

the average tariffs. This is a hybrid between a pure cost-based Zonal tariff

and Postal Tariff. It serves the objectives of respecting location economics

and ensuring efficiency, while at the same time ensuring that small off-

takes at underserved locations are not charged excessively high tariffs. The

regulator is the appropriate agency to take a call on this based on actual

data on both costs and the geographical distribution of demand loads.

0.xxvii. For Price Discovery, the Committee felt that the process should reflectopportunity costs, adequacy of incentives for exploration and production

(E&P) and fairness to the consumer. It has recommended a procedure for

arriving at an inferred price by taking the average of the 12-month trailing

Henry Hub price on the one hand and the 12-month trailing producer net

back price (excluding shipping & liquefaction computed on a normative

basis that is discussed in the body of the report) derived from the Japan

Korea Marker (JKM) price or equivalent Asian LNG price forPersian/Arab Gulf sources of supply. On the basis of this inferred price,

the Government should then set a premium or a discount, depending on

extant conditions on what the perception is with regard to it being: (a)

adequate for attracting investment in the E&P and (b) not excessive for the

consumer.

0.xxviii. There is a recommendation by this Committee to align the import duty onLNG with that of crude petroleum and to work towards declared good

status for natural gas/LNG. The Department of Revenue is not agreed to

the proposal for aligning import duty on LNG with that of crude

petroleum. On the issue of declared good status in regard of VAT, the

Department of Revenue did not wish to record a view.

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CHAPTER I

ANALYSIS &RECOMMENDATIONS

This chapter deals with the approach and the framework of analysis adopted as well as

the recommendations being made in this report. In subsequent chapters, some of the

more in-depth background and context has been placed. In an annex to the report

highlights from the report of the consultant M/s Mercados appointed by GAIL on the

subject has been appended at Annex-1 for information.

1.0 Background and Problem

1.1 The demand for natural gas in India is far exceeding the domestic output. It is

most likely that the incremental requirements of natural gas in India for the

next 510 years (i.e. 2016/17 which is the terminal year of the Twelfth Plan

and up to 2021/22 that is, the terminal year of the Thirteenth Plan) are going to

be significantly greater than the increments to domestic output which may be

reasonably expected. Therefore, the import component of total domestic

consumption will have to rise.

1.2 Government policy has clearly recognized the problem as being one ofallocation of scarce resources. The scarcity is embodied in the widely different

prices at which natural gas is available in the country. Domestic gas is priced

at $4.20/mmbtu in most cases + pipeline charges + taxes. There are a few

sources of domestic gas that is priced at a slightly higher rate, but that too is

only about $1.01.3/mmbtu more costly. On the other hand, imported R-LNG,

except for contracted supplies from Qatar (which are due for price resetting in

the near future) costs $1014/mmbtu + pipeline charges + taxes. Obviously,

every rational consumer in this situation would like to have preferential access

to domestic natural gas.

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1.3 Government has made a clear distinction between what it considers priority orcore and the non-priority or non-core sectors. It has clearly enunciated the

need to place fertilizer and power sector in the priority segment, while keeping

other industrial users such as petrochemicals, refineries, sponge iron etc. in the

non-priority sector.

1.4 There are two underlying logical threads for arriving at this conclusion.1.5 First, fertilizer and power are in a sense vital to the national interest, require

substantial amounts of gas and involves large capital investments that is, the

sunk costs are large.

1.6 Second, both the fertilizer and power sector operate in an environment wherethe price of their output is subject to government regulation, either directly or

indirectly. Thus, the selling price of urea is much below the operating cost,

large government subsidies are involved and, there is limitation on the ability

of companies to change the selling price. It is unlikely that in the foreseeable

future, fertilizer companies will be able to set their selling prices near their

operating costs and will therefore continue, to be dependent on the subsidyregime.

1.7 In the case of power, natural gas based producers have to compete with otherswho are based on domestic coal. Domestic coal prices have been regulated and

are much lower than that of imported coal, even after adjusting for relative

heat values. Further, on heat value basis, domestic coal is much cheaper than

natural gas. The state electricity regulators are obliged to adopt a merit order

dispatch. Power producers, who use natural gas, especially R-LNG, are thus at

a great disadvantage in being able to sell their power. At the same time, there

is a huge power scarcity in the country. Many manufacturing plants, as well as

commercial establishments, have been forced because of the power shortage,

to use diesel based generating sets that are highly uneconomical and the cost

of such captive power is much more than R-LNG based power.

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1.8 It is, therefore, in the larger national interest to ensure that power producedfrom natural gas, including R-LNG, is able to be dispatched and is affordable

to the distribution companies who are financially quite constrained. It is an

acknowledged fact that revising certain kinds of electricity tariffs, such as that

for households and for agriculture has faced and will continue to be a

challenge. Thus, there are regulatory and institutional bottlenecks in the path

of gas based power producers to be able to realize the full cost of their

generation and this difficulty escalates if that cost is higher, as indeed is the

case with R-LNG.

1.9 Therefore, in the light of the above discussion, our own extant policy may beseen as one that expressly provides preferential access for power and fertilizer

units to domestic natural gas. It is proposed that this should form the

cornerstone to the framework of the solution to the allocation problem which

sits at the heart of the present Committees terms of reference.

Table 1.1 Natural Gas Production and ImportsUnit: mmscmd

2009/10 2010/11June

2011/12

1 Domestic Natural Gas Output 130.34 142.55 132.50

2 Less internal consumption, injection,producer pipelines & flaring

14.76 12.82 9.07

3 Net Domestic Natural Gas available 12 115.58 129.73 123.43

4 Less LPG & C2C3 extraction 8.12 8.20 10.78

5 Distribution pipeline internalconsumption

2.01 2.47 2.06

6 Domestic Natural Gas available forgeneral consumption

345 105.45 119.06 110.59

Of which: Isolated customers 2.01 2.01 2.01

7 Imported R-LNG 32.35 37.20 46.33

8 Total Natural Gas available

(including isolated customers)

6 + 7137.80 156.26 156.92

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2.0 Proposed Scheme of Preferential Allocation

2.1 It is proposed that in the first instance, domestic gas be preferentially provided

to the priority sector, as defined to include the fertilizer and power industries.It may be noted that, as on date, both the fertilizer and power sector do source

a part of their requirements from imports. The proportion of R-LNG to total

consumption was 19 and 12 per cent respectively in 2009/10 and 17 and 9 per

cent respectively in 2010/11 for the fertilizer and power sectors respectively

(see Table 1.2). The substitution of existing R-LNG supplies with domestic

supplies for power and fertilizer is not being considered in this report, given

the order of the present shortage and even more that of the prospectiveshortage.

2.2 In the first instance, as an approximation to start with the total availability of

domestic natural gas is fixed at the present level. Subsequently, we will

examine what the situation will look like as we incorporate different levels of

incremental domestic natural gas output. The scheme then is visualized to

operate as below:

i. The total amount of domestic natural gas that is estimated to be available in2011/12 is 123.43 mmscmd. This excludes gas that is required in the gas field

itself for internal consumption, injection & flaring, but not that required for

LPG and C2-C3 extraction and pipeline engines (see Table 1.1). This is on the

basis of the situation obtaining in June 2011. Conditions may change

somewhat during the course of the year, but the argument that follows will be

unaffected.

ii. After LPG and C2C3 extraction (9.07 mmscmd) and internal consumption indistribution pipelines (2.06 mmscmd) a balance of 110.59 mmscmd will be

available for general consumption (see Table 1.1)

iii. This estimated domestic gas availability in 2011/12 of 110.59 mmscmd is tobe then allocated to the power and fertilizer industries at the present rates of

domestic off-take. The domestic gas output in June 2011 has been slightly

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adjusted for the fertilizer sector to bring it in line with its allocations and

closer to the level that obtained in 2010/11. The total adjusted domestic gas

drawal by the fertilizer and power sector is then 88.37 mmscmd. The net

position between the availability of 110.59 mmscmd and 88.37 mmscmd

leaves a balance of 22.20 mmscmd (see Table 1.4).

iv. Thus far, the city gas and CNG (CGD & CNG) and Court mandated customershave been treated as part of the core sector, as has LPG/C2C3 extraction. It

may be noted that LPG/C2C3 extraction is in any case essential. The Court

mandate has been to make the gas available, but not at any particular price. At

the moment these customers at the aggregate level receive a mix of domestic

natural gas and R-LNG. It is believed that these Court mandated consumers

(which include some of the CGD/CNG operations) work in a market

environment and should be able to absorb an increase in supply prices of gas.

However, it may be appropriate to cap their access to domestic gas at about

the present levels.

v. In regard of CGD and CNG, the economics appear to suggest that even withR-LNG the business should be competitive (see Table 1.3). The cost of R-LNG based CNG in heat value terms is only 20 per cent higher than the

present sale price in Delhi and actually less than that it is in Ahmedabad.

Since, there will continue to be allocation at the rate of 6.0 mmscmd of

domestic gas, the impact of picking up incremental needs from R-LNG should

be eminently manageable and the necessary adjustments in selling price will

not be large and should be acceptable. This is especially considering the

enormous cost differential that is there even with respect to HS Diesel which

is being subsidized today. The actual consumption of CGD/CNG in 2010/11

was 5.34 mmscmd from domestic gas and 2.56 mmscmd from R-LNG. It is

proposed to cap the off-take of this sector from domestic gas to 6.0 mmscmd.

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Table 1.2 Sectoral Consumption of Natural Gas including R-LNGUnit: mmscmd

2009/10 2010/11 June 2011 Adjusted

Qty Ratio Qty Ratio Qty Ratio Qty. Ratio

Power Sector

Domestic 49.67 (88%) 56.22 (91%) 56.37 (92%) 56.37 (92%)

R-LNG 6.74 (12%) 5.38 (9%) 5.05 (8%) 5.05 (8%)

Sub Total 56.42 61.60 61.41 61.41

Fertilizer Sector

Domestic 30.33 (81%) 33.10 (83%) 29.56 (78%) 32.00 (80%)

R-LNG 7.04 (19%) 6.76 (17%) 8.18 (22%) 8.00 (20%)

Sub Total 37.37 39.86 37.74 40.00

CGD/CNG

Domestic 6.40 (93%) 7.05 (62%) 5.34 (68%) 6.00 (76%)

R-LNG 0.14 (7%) 4.32 (38%) 2.56 (32%) 1.90 (24%)

Sub Total 6.54 11.37 7.90 7.90

Power andFertilizer sectors

Domestic 80.00 (85%) 89.32 (88%) 85.93 (87%) 88.37 (87%)

R-LNG 13.78 (15%) 12.14 (12%) 13.23 (13%) 13.05 (13%)Sub Total 93.78 101.46 99.16 101.42

Table 1.3 Comparison between Price of liquid Automotive Fuels, CNG and Gas

from R-LNG

UnitRetailSellingPrice(RSP)

Calorificvalue in Kcal

per unit

RSP converted toheat value in paise

per K Cal

1 Motor Spirit Delhi Rs / Litre 63.38 8,798 0.7204

2. HS Diesel Delhi Rs / Litre 41.12 7,700 0.5340

3 CNG Delhi Rs / Kg 29.80 10,956 0.2720

CNG Mumbai Rs / Kg 31.47 10,956 0.2872

CNG Ahmedabad Rs / Kg 40.25 10,956 0.3674

4. R-LNG CIF $ / mmbtu 12.00

Ex-Delhi Rs / kg 42.07 12,870 0.3269

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vi. In regard of the court mandated customers other than CNG, the present off-take is 0.89 mmscmd from domestic gas and 0.20 mmscmd from R-LNG.

Though they may have some paying capacity, in the interest of ease of

transition (since their needs may increase in the future) allocation towards

these customers may be capped at 1.0 mmscmd. The rest of their needs may be

met by blending with R-LNG.

vii. That would leave 22.206.001.00 = 10.22, say 10.0 mmscmd for purposes ofeither a substitution of R-LNG requirements by power and fertilizers or for

other users. Since it is being proposed that the present R-LNG used by power

and fertilizer should not be substituted, this 10.0 mmscmd is available for

either incremental use by the fertilizer and power sector or for non-priority use

or a combination of the two,

viii. Presently as is evident from Table 1.4, non-priority users, as in June 2011, areusing domestic natural gas to the extent of about 18.43 mmscmd. The

suppliers, mostly GAIL and also others, have contracts with these customers.

Though there are saving clauses which can permit the supplier to meet their

quantitative obligations from R-LNG, there may be disputes and litigation.Further, the magnitude of the shock if all of this 18.43 mmscmd is substituted

wholly by R-LNG may be excessive. It is accordingly being recommended

that an amount of 5.0 mmscmd1 be set aside for meeting the needs of the non-

priority sectors, the balance requirement to be substituted by R-LNG.

ix. That will leave a balance of 10.22 mmscmd say 10.0 mmscmd, for additionalpreferential allocation to the fertilizer and power sectors. Till additional

requirement from new power or fertilizer capacity is forthcoming, thisquantum of 10.0 mmscmd may be made available to other users.

1 This quantum of 5.0 mmscmd must include the non-power, non-fertilizer use in isolated gas

fields, such as tea factories and similar users. The total gas coming from isolated gas fields is 2.01

mmscmd presently. Most of this is being used in the power and fertilizer sector and some in the

CGD/CNG sector (which would be anyway covered under the 6.0 mmscmd set aside for this use). A

small amount is being used by other category of users which would be grouped under this head of 5.0

mmscmd.

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Table 1.4 Utilization of Domestic Natural Gas

On Unchanged Domestic Gas Output Basis

Unit: mmscmd

2010/11 Base line for 2011/12 & futureyears

1. Net domestic gas available 119.06 110.59

2. Less: Fertiliser & power at presentoff-take level

89.32 88.37

3. Net gas available (12) 29.74 22.22

4a Less: For CGD/CNG 7.05 6.00

4b Less: For other Court mandatedcustomers

0.89 1.00

5 Net available for additional needsof fertiliser & power sectors

(34a4b)

21.80 10.22, say 10.00

x. During the course of 2011/12 an additional quantum of about 16 mmscmd (ormore) is going to be needed by the power sector. If all of this is met from

domestic natural gas, the balance that will be left for other users will be () 6

mmscmd, that is the entirety of the 16 mmscmd requirement cannot be met

from domestic gas and a part of it will have to come from imported R-LNG.

xi. The point has been raised that merchant power plants which do not have anyobligations to sell under a Power Purchase Agreement to Dist Coms./ SEBs,

but are free to sell to the highest bidder, ought not to avail of preferential gas

allotment. The present policy of Power Ministry requires all power plants who

apply for linkage to have a PPA for at least 85 per cent of their generation.

2.3 In working out what the allocation procedure will result in (Table 1.5), we first

try and meet the incremental needs of the fertilizer sector arising on account of

switching from LSHS/FO and naphtha to natural gas and that on account of

de-bottlenecking and new plants. We have maintained the composition of

incremental demand from the fertilizer sector at 75 per cent domestic gas and

25 per cent imported R-LNG. That results in an average position of around

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2122 per cent of R-LNG use in the consumption basket for the fertilizer

industry in the future years up to the end of the Twelfth Plan period.

Table 1.5 Utilization of Domestic Natural Gas

On Unchanged Domestic Gas Output Basis

Unit: mmscmd

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

1 Net available natural gas foradditional needs of fertiliser &power sectors

21.8 10.22, say 10.0

Additional Requirement of Fertiliser Sector

(a) Switching LSHS/FO & Naphtha 3.8 4.0 2.2

(b) Debottlenecking 1.0 2.0 1.0

(c) New plants 4.0 7.0 3.0

2.

4.8 6.0 7.2 7.0 3.0

Consumption of Fertiliser Sector

Domestic Gas 33.1 32.0 35.6 40.1 45.5 50.8 53.0

Imported R-LNG 6.8 8.0 9.2 12.7 14.5 16.3 17.0

Total 39.9 40.0 44.8 50.8 58.0 65.0 68.0

3.

Proportion of R-LNG 17% 20% 21% 21% 22% 22% 22%

4. Net gas available after Fertiliserfor New Needs of Power Sector

7.6 6.4 1.9 3.5 8.8 11.0

Consumption of Power Sector

a) Additional Needs 16.0 26.0 16.0 3.0

b) Total Consumption Domestic Gas 56.2 63.9 70.3 72.3 68.7 60.0 49.0

Imported R-LNG 5.4 13.5 33.1 47.2 53.7 62.4 73.4

Total 61.6 77.4 103.4 119.4 122.4 122.4 122.4

5.

Proportion of R-LNG 9% 17% 32% 40% 44% 51% 60%

2.4 It should be made clear that the 2122 per cent R-LNG results out of the way

the incremental requirements are being satisfied through allocation. It does not

have implications for existing supplies.

2.5 Then we look to the additional needs of the power sector. A phasing has been

done, keeping in mind the completion of about 12,200 MW through 2011/12,

2012/13 and 2013/14. What then results is a sharp increase in the R-LNG

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component of the power sectors consumption to 40 per cent in 2013/14 and

60 per cent by 2016/17 (Table 1.5).

3.0 Impact of the Future Increase in Domestic Gas Output

3.1 Next we relax the constraint on domestic gas output, which so far has been

kept fixed at the base level corresponding to the position in June 2011. Four

scenarios have been examined. These increase the level of net domestic gas

availability after oil/gas-field internal consumption, LPG/C2C3 extraction

and pipeline internal consumption.2 In the first scenario, it is assumed that

there will be an increase of 6.0 mmscmd in each year at the level of net

domestic gas availability after internal consumption in oil/gas fields, LPG/C2

C3 extraction and pipeline internal consumption. The second scenario takes an

8.0 mmscmd increase in each year. The third with 12.0 mmscmd increase in

each year. The fourth scenario envisages an addition of 16.0 mmscmd in each

year.

3.2 To put it alternatively, the first scenario envisages gross domestic gas output

to rise from 132.5 mmscmd in June 2011 to about 189 mmscmd by 2016/17,

which is a very modest expectation. The second scenario envisages a larger

increase by 2016/17 to about 199 mmscmd which is also reasonably in the

feasible range. The third and fourth scenarios envisage a much larger increase

of 12.0 and 16.0 mmscmd in each year and a gross output level in 2016/17 of

219 mmscmd and 239 mmscmd which are on the optimistic side.

3.3 As may be seen from Table 1.6, that only in the most optimistic scenario

(namely, Scenario #4) will there be adequate domestic gas to meet the entirety

2 As on June 2011, the proportion of domestic gas available after oil/gas field internalconsumption, injection & flaring, LPG/C2C3 extraction and pipeline internal consumption is 83.5 per

cent. This proportion has been used to arrive at the corresponding gross natural gas output level. Thus

an additional 6 mmscmd net gas available at this level would translate to 6.0 0.853 = 7.04 mmscmd

of additional gross gas output.

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of the needs of the power sector, which does not include the requirements of

new gas based power plants, beyond the 12,200 MW that is due for

completion in 2011/12 to 2013/14.

Table 1.6 With Incremental Domestic Natural Gas Going Entirely to PowerSector

2013/14 2014/15 2015/16 2016/17

Composition of Power Sector Consumption with unchanged domestic gas outputI.

Proportion of imported R-LNG 40% 44% 51% 60%

With projected increase in domestic gas output the proportion of imported R-LNG now comes to

Scenario #1

[@ additional 6 mmscmd each year]*

26% 29% 31% 35%

Scenario #2


26% 24% 25% 27%

Scenario #3


19% 14% 12% 11%

II.

Scenario #4


13% 5% 1% 5%

Note: * Each year there is an increment in net domestic availability of stated amount. That is, inScenario #1, by 2016/17, the total incremental output would be 30 mmscmd and in Scenario#4, it would be 80 mmscmd.Negative proportions under Scenario#4 means that the complete needs of the power sector aremet from domestic gas and there is a surplus over and beyond that for use by other sectors.That is, on the assumption that there are no new gas based plants that would come up in theclosing years of the Twelfth Plan.

3.4 Thus, even with domestic gas output potential greatly relaxed, the

prioritization of fertilizer and power sector is clearly unavoidable.

3.5 If, however, domestic gas turns out to be along the lines envisaged in

Scenario#4 or even better and as a result there is a surplus of domestic gas

after meeting the needs of the fertilizer and the power sector to the extent of

75 per cent, then the excess should be allocated to the non-priority users.

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3.6 In the light of the shortage of domestic gas, it is clear that users other than

power and fertilizer will have to meet the large part of their needs from R-

LNG. It is further obvious that even the power and the fertilizer sector will

have to meet a part of the incremental needs from imported R-LNG. This is

especially true for the power sector whose incremental requirements in their

coming years are going to be quite large.

3.7 Thus, the basic arithmetic even as it preferentially allocates domestic natural

gas to the power and fertilizer sector, only succeeds in mitigating, not

eliminating, the extent to which the import dependence of the fertilizer and

power sectors would rise, given their increasing requirements.

4.0 Previous Commitments

4.1 There is an extant CCEA decision in regard to the gas requirement for units

that are switching from LSHS/FO and naphtha that it may be ensured that full

allotment of future gas should be made to the requirement as projected for

fertilizer industry on priority. One option would be to place these needs (3.80mmscmd for LSHS/FO and 8.45 mmscmd for naphtha) to the extent of 100

per cent on domestic gas.

4.2 However, as has been seen, even at the moment imports account for about 19

22 per cent of the gas that is being consumed by fertilizer units. Further, there

will be a subsidy regime in place for such units and if the incremental

allocation is made on the basis of 75 per cent domestic and 25 per cent R-LNG

that subsidy regime will recognize it. Further, if for other existing and new

units the R-LNG proportion is also placed at 25 per cent it is a more

symmetric treatment if the eight units that are switching from liquid fuels to

gas feedstock are treated in a uniform fashion that is identical to the rest of the

industry. As may be seen from Table 1.5, the overall R-LNG component of the

consumption basket for the fertilizer industry is maintained at around 2122

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per cent. In any case, the subsidy regime will have to take into account the

allocation and its implications.

5.0 Isolated Gas Fields

5.1 As may be seen from the previous tables there is a production of about 2.1

mmscmd of natural gas from gas fields that are not connected to the gird. This

gas is being utilized locally and cannot be allocated to customers who are not

in that geographical location. A large part of this gas is being used for power

plants and the balance is being used for a variety of applications that includes

industry for example, tea factories in Assam. The recommendations made here

do not envisage any change in the pattern of consumption for these isolated

fields. This fact does not substantially change the nature of the

recommendations, given that the bulk of this isolated gas fields output is being

used for power generation, the broad tenor of the recommendations will be

implicitly adopted in the case of these isolated gas fields. The adjustment that

is implicit here has been spelt out previously.3

6.0 Pipe Line Tariff

6.1 In the latter section of this report, the issue of pipeline tariff and postal tariff

has been discussed at some length. The latter (postal tariff) is a means of

equalizing the freight cost at different destinations. In the view of the

Committee, complete freight equalization may not be desirable from the

consideration of locational efficiency. At the same time, very widely varying

tariff cost on account of a lack of economies of scale may also not be in the

larger public interest.

6.2 It is possible to conceive of a situation where we adopt a hybrid position,

where by and large the pipeline tariff reflects the actual transportation cost, but

the outlier pipeline tariff is mandated not to exceed a certain proportion of the

3 See footnote 1

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average tariff, say by 50 per cent. This is on the assumption that the bulk of

the off-take will take place at locations that are near the average or below the

average pipeline tariff and the more distant locations will account for a

relatively smaller part of consumption If this is taken as a policy advice, the

pipeline regulator may be allowed to work out the details within this

framework. The regulator is the appropriate agency to take a call on this based

on actual data on both costs and the geographical distribution of demand

loads.

7.0 Pooling/Preferential Allotment

7.1 The recommendations put forth here do not envisage any form of pooling at

the all-India level cutting across industries. What it does is to preferentially

allot available domestic natural gas to fertilizer and power sectors with a

certain reserved allotment for the CGD/CNG sector. Further this preferential

allotment is with respect to the incremental needs of the preferred industry,

rather than to their existing usage.

7.2 Following from this, the concerned administrative ministries dealing with

fertilizer and power will have to ensure that the incremental requirement is

fulfilled in the fashion that has been described in this report.

7.3 In the case of the fertilizer industry, the recommendations that is currently

before the CCEA is that up to the cut-off point, the department through

FICC, will operate a notional gas pooling so that different plants participatingin the pool will be able to get gas at a common price.

7.4 In addition, the Department of Fertilizers will have to ensure that in the

incremental requirements of the industry, the allocation procedure suggested

here is implemented by using the 75 (domestic): 25 (imported) formula.

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7.5 In the case of the power sector, the Ministry of Power in conjunction with

MoPNG will have to ensure that the incremental requirements of the sector are

met in the preferential manner delineated here. They should seek to try and

ensure a fair allocation, whereby individual power units for the incremental

requirements are allocated the domestic gas in such a way that broadly the

overall resultant ratio applies at least within a power company if not

specifically across every single utility. It however would be preferable to do

this with respect to individual utilities, since it is conceivable that ownership

of a specific utility could change over time.

7.6 The Ministry of Petroleum & Natural Gas will have to coordinate the overall

procedure.

7.7 It may be noted that the scheme being proposed here is somewhat similar to

Option B as proposed by the Mercados report extracts of which are placed as

an Annex-1 to this report.

8.0 Contract and Swap

8.1 It is proposed that the allocation of gas does not involve physical pooling.

Indeed it is best that it operate as a simple allocation procedure. That is, each

user will lift X units of domestic gas, in the understanding that he will lift a

pre-specified Y unit of R-LNG. This the element of proportionate pricing

charged by the provider of gas, irrespective of the physical origin of the gas

can reflect this ratio of X:Y. The customer should of course have a choice of

sourcing the Y units of R-LNG on his own which will serve the ends of

competitive sourcing and price efficiency. However, if in certain cases, it is

felt necessary that a notional pooling of existing contracts is the only way to

serve the objectives of an efficient and simple settlement this can be worked

out through the use of swaps.

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8.2 Thus once the allocation formula is used and a said party A is to be provided

domestic gas to the extent of 75 per cent and imported R-LNG of 25 per cent,

then two eventualities can arise. The customer may choose to search out his

own supply of R-LNG. Alternatively, if its supply contracts is such that

domestic is 60 per cent or for that matter 80 per cent, then the difference will

have to be swapped with someone else. Likewise, for a unit in the non-priority

sector having contract for supply of domestic gas in excess of the amount that

is available under the caps spelt out previously, that unit will have to be swap

with a priority user who is permitted incremental supplies of domestic gas in

keeping this need with the preferential allotment principle. Government of

India must ensure that these swaps do not attract taxes of any kind if the swaps

are made through the MoPNG as a part of the policy measure. In the case of

incremental domestic gas output the preferential allotment should directly

result in a contract and there may not be a need for a swap.

9.0 Taxes on Natural Gas/LNG

9.1 Presently there is varying VAT on natural gas, including LNG, across thecountry. It may be advisable for the Government to treat LNG/Natural Gas as

a declared good so that they have a common concessional rate of VAT.

9.2 Import of LNG presently attracts Basic Customs Duty of 5 per cent ad

valorem. Till 25 June 2011, this was the same rate that the import of crude

petroleum attracted. There is no justification to have differential tax treatments

for LNG and crude petroleum. The Committee recommends that the import

duty of LNG may be made identical to that of the import duty of crude

petroleum, which presently is zero. If in future a non-zero import duty is

levied on crude petroleum, the same rate may be made applicable to LNG.

9.3 It may be noted that though there is a 2.5 per cent import duty on several

refined petroleum products, this is largely notional since the actual imports of

liquid hydrocarbons is overwhelmingly in the form of crude petroleum. If a

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uniform tax treatment is not extended on import duty as between crude

petroleum and LNG, there will be needless discrimination against the latter,

given that the cost per calorific unit to the user is less in the case of LNG than

in the case of crude petroleum. It may be pointed out that unlike crude

petroleum, where it is the light and middle distillates that perform a valuable

energy function, the entirety of LNG is directly usable in a highly efficient

fashion. Further, the use of LNG is environmentally friendlier than is the case

with crude petroleum or rather refined petroleum products.

10.0 Domestic Natural Gas Prices10.1 Traditionally, crude oil markets have been deep and active. As a result, natural

gas/LNG began to be priced in relation to widely traded crude oil marker

prices. Our contracts from Qatar were based on such a formula. These

formulae have in the past provided for a floor and cap to the price of crude oil

and the indexation process resulted in a certain discount in terms of calorific

value from the marker crude price.

10.2 On the discovery of the KG Basin, a similar formula was developed. The

Empowered Group of Ministers (EGOM) decided the following price

indexation formula for natural gas to be sold from KG basin:

Gas Price ($/mmbtu) = 2.5 + (CP25) ^ 0.15

Where, CP is annual average Brent crude price for the previous FY with a cap

of $60/bbl & floor of $25/bbl. The price comes to US$ 4.20 per mmbtu for

crude at a cap of $60/bbl

Existing Gas Price contracts in the Country

10.3 Currently, in India there are multiple prices for gas sold by different

producers. The status of volume and price is given below in the Table 1.7:

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Table 1.7 Status of Supply and Price

S.No. Producer Sales (mmscmd) Price ($/MMBTU)

1. ONGC (APM) 49 4.20

2. ONGC (Non APM) 1.46 4.75

3. ONGC (North East) 2.19 2.54

4. OIL 5.2 2.54*

5. PMT / Ravva / Lakhmi 17 5.28

6. RIL-KG-D6 48 4.20

7. R-LNG (Long-Term) 28 6.50

8. LNG (Spot) 8 10 12 14

Total Gas 159 161

Note: LPG/C2-C3 extractable & internal Consumption includes 10 12 MMSCMD of gas

*40 per cent price compensated from the budget

Source: GAIL

11.0 Price Discovery

11.1 The Committee has been asked to examine what should be the procedure for

discovery of gas price. It is fairly obvious that India will be a substantial

importer of natural gas/LNG and also of crude oil. It is also self-evident that

the world price of crude oil will remain elevated.

11.2 There is today a great disparity between the prevalent prices in the North

American market (which is the largest gas market in the world) and the Asia

Pacific market. The discovery of shale gas and other non-conventional gas has

led to the North American prices settling at quite low levels of around $ 4.0

4.5 per mmbtu. This is in sharp contrast to the Asia Pacific prices where LNG

(the tradable form of natural gas in such markets) has gone to as high as $14

per mmbtu following on the March 2011 Tsunami in Japan and dislocation of

its nuclear power facilities.

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11.3 It is in our national interest that exploration and production (E&P) activities

for natural gas and non-conventional gases proceed rapidly. For that to

happen, the indicative pricing of future domestic natural gas production should

realistically reflective the opportunity cost of such investment.

11.4 One view that may be taken is that as we live in the Asia Pacific market, hence

it is that price which should be relevant.

11.5 However, it is impossible to conceive of a situation where the Asia Pacific

market prices will continue to be so completely at odds with prices prevailing

in the North American market. The huge difference in price is an arbitrage

opportunity. Normal market dynamics will always consume such arbitrage

opportunities and result in the equalization of prices. There is a cost to make

the arbitrage work, which is the cost of liquefaction and transportation. By no

stretch of imagination is this cost equal to the present difference between the

North American markets and the peak Asia Pacific LNG spot prices.

11.6 The simplest approach to evolve a reference price for future price discovery is

to take a simple average between the Henry Hub (US) prices and that of the

Asia Pacific LNG (JKM or Japan Korea Marker), the latter being reduced to

the extent of shipping, liquefaction and associated charges or as has been

described by some as the netback value or the producer netback. It should be

noted that there is a concept ofnet back price in the LNG trade which is a bit

of a notional calculation.

11.7 The Energy Intelligence Agency (EIA) of the Department of Energy of the US

federal government reports that:

Netbacks are calculated using a long-term charter rate of $65,000 per day

for 138,000 cubic meter tankers. Re-gasification fees in the United States

and the United Kingdom are taken as 10 percent of the base price. U.S.

netbacks are calculated using the first and second month out closing price

taken from the New York Mercantile Exchange (NYMEX) on the 3

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trading days before and including the date reported. A local adjustment for

delivery to the Lake Charles terminal is made using prior month spot

prices reported by Natural Gas Week. The calculation of United Kingdom

netbacks comes from an average of the closing price on the

Intercontinental Exchange (ICE) futures contract for delivery at National

Balancing Point (NBP) on the first and second months out. Japanese

netbacks are derived from the official average ex-ship prices for the most

recent month. A World Gas Intelligence European Border Price table is

used to estimate the most recent ex-ship prices for Spanish netbacks.4

11.8 Trade journals such as the New York based World Gas Intelligence (weekly)

regularly reports volumes and prices for Asian LNG markets and Spot LNG

Exporter netbacks at key worldwide markets. These reported netbacks are

appears to be the CIF prices reduced by normative shipping costs perhaps as

described in the previous paragraph,

11.9 In so far as the JKM marker LNG price is concerned, for our purposes, we

should compute the producer netback starting from the reported Asian LNG

price, less the normative shipping cost to Qatar, which is regularly reported in

the trade literature. From this, we need to subtract the liquefaction cost again

on a normative basis, by say $2.50 per mmbtu. This will give us the gas

producers net back value.

11.10 To illustrate at the present time, the Henry Hub spot price is $3.94 per mmbtu.

The reported LNG netback at Qatar from North East Asian markets (JKM

marker) was $12.64 per mmbtu. Reduced by the normative $2.50 towards

liquefaction this comes to $12.642.50 = $10.14 per mmbtu. The simple

average of Henry Hub sport and this computed producer netback price is $7.04

per mmbtu.

4 Short-term Energy Outlook Supplement, US LNG Imports the Next Wave, Damien Gaul andKobi Platt, EIA, January 2007, p.7

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11.11 These calculations are based on spot prices. It is obviously better to eliminate

momentary price spikes by adopting a 12-month trailing average.

11.12 The calculation based on 12-month trailing average should be treated as a

reference price which has indeed been discovered from the market. However,

it need not necessarily be the operational price but an inferred price. This latter

price can then be the basis for being combined with either a discount or a

premium which may be applied, given the view taken by the policy

establishment in light of the combined criteria of fairness to the consumer and

adequacy of incentive to the E&P enterprise.

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CHAPTER II

Energy Consumption Trends

12.0 Primary Energy of which Oil & Gas

12.1 Energy is a key component of a modern society and a vital ingredient for

economic growth. The world consumed over 12,000 million tonnes oil

equivalent (mtoe) of primary energy in 2010, while the Asia Pacific region

consumed over 4,500 mtoe and India 477 mtoe in 2010/11. India is the fifth

largest energy consumer in the world with oil and gas constituting about 45

per cent of (gross) primary energy consumption, of which 35 percentage

points is from crude oil and 10 percentage points from natural gas. The size of

the oil and gas industry in India in terms of turnover is around $160 billion.

The value of crude oil and LNG imports into India in 2010/11 was around

US$98 billion. About 78 per cent of Indias petroleum consumption is met

from imports (mostly of crude oil), while about 25 per cent of natural gas

(including LNG) consumption comes from imports.

13.0 Growth in Consumption Natural Gas

13.1 Global consumption of primary commercial energy (coal, oil & natural gas,

nuclear and major hydro) has grown at the rate of 2.6 per cent over the last

decade. In the Asia Pacific region, the growth rate is close to 6 per cent while

that for India is around 6.8 per cent. Globally, natural gas consumption has

grown by 2.7 per cent over the past decade while that in the Asia Pacific

region growth has been 6.8 per cent. India with a low base of natural gas

consumption has seen very rapid growth trending 8.7 per cent (including

LNG) over the past 11 years. Total natural gas consumption world wide in

2010 was 3,169 billion cubic meters (BCM). The International Energy Agency

has projected that natural gas consumption worldwide will increase by 1.4 per

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cent per annum in its base case between 2008 and 2035. That would take total

natural gas demand to over 4,300 BCM by 2035.

14.0 Natural Gas pipelines and LNG

14.1 Of global natural gas consumption of over 3,000 BCM, about 20 per cent

involves cross-border movement, either through transnational pipelines or in

the form of LNG. The LNG trade constitutes 7.5 per cent of global natural gas

consumption.

15.0 Reserves and Producing Countries

15.1 The major conventional natural gas reserves in the world are in Russia, Iran,

Qatar, Turkmenistan and the USA. 40 per cent of global assessed conventional

natural gas reserve is in Russia and in Iran. The important fact to note is that

the major gas reserves with the exception of the US are away from mature

markets. The USA is the worlds largest gas producing country and also the

largest gas consuming country, with output of around 600 BCM and

consumption of around 647 BCM. Russia is the second largest gas producing

country with output of 520 BCM and consumption of around 400 BCM, with

the balance being exported to European countries through transnational

pipelines. Recently, with the commissioning of the Sakhalin liquefaction

terminal, Russia has also entered into the LNG exporting business.

16.0 Liquefied Natural Gas

16.1 Around 200 million tonnes per annum (mtpa) of LNG is produced and

exported globally by some 17 countries. Qatar is the largest LNG exporter in

the world with an installed capacity of 77 mtpa. The other major LNG

producers/exporters are Malaysia, Indonesia and Australia. Australia is in the

process of adding large LNG capacities and is expected by 2015 to rival Qatar

as the pre-eminent LNG exporter. Of the total LNG produced globally, around

7075 per cent is consumed in the Asia-Pacific region. The five major

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importing countries in the Asia Pacific are Japan, South Korea, Taiwan, China

and India. The balance 25 per cent volume of LNG is consumed in 22 other

countries, mostly in Western Europe, including Spain, France, UK and

Belgium. Re-gasification capacity in the world is around 560 mtpa with the

US alone having re-gasification infrastructure of about 140 mtpa.

17.0 Shale and Other Unconventional Gases

17.1 The last decades high gas prices have seen the emergence as major sources of

unconventional gases such as shale gas. In the US today, nearly 4050 per

cent of total gas consumption is reported to be coming from these

unconventional sources. The US is estimated to have vast reserves of shale

gas. In the American continent assessed Canadian shale gas deposits rival that

of the US and Argentina has been recently assessed to have deposits of a

similar magnitude.

18.0 Impact of gas prices

18.1 The emergence of shale gas as a major source of additional supply has altered

the character of the North American gas market. The Henry Hub gas price in

the US has been hovering around $4 per million BTU (mmbtu) ever since the

global economic crisis which saw a sharp decline in gas prices worldwide.

However, unlike Henry Hub, the other benchmark prices for natural gas have

picked up sharply over the past two years with UK benchmark (New

Balancing Point or NBP) at around $911 per mmbtu and the Pacific Mark

benchmark price (Japan/Korea Marker or JKM) at around $1014 per mmbtu.

In other words, a huge spread has developed in the two years since the Crisis

between North American natural gas prices and that in the Asia-Pacific. Given

the large potential for incremental supplies of shale gas there is also the strong

potential of being able to equalize market prices between the North American

and Asia-Pacific regions through the physical movement of LNG.

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19.0 Likely Trajectory of Global Gas Demand

19.1 Global gas demand is expected to continue to show robust growth, although

the pace of the growth beyond 2020 may slow due to both economic andenvironmental factors.

19.2 Phase 1 2011 to 2020 - Factors underlying strong growth in consumption:

o Growth is likely to be driven by a combination of preference for naturalgas in the fossil fuel portfolio of developed countries and the economic

recovery and attendant demand growth especially in Asia and other non-

OECD markets.o The potential impact of rising energy efficiency, renewable and new

technologies in the erosion of demand for natural gas may be limited.

o CO2 and other emission regulation/legislation is likely to continue to pushcoal to gas substitution.

19.3 Phase II 2020 to 2030 - Continued growth but with greater uncertainty:

o Growth will continue to be driven by Asian markets while theconsumption in the US and Europe is likely to plateau. Renewable and

nuclear sources of energy will begin to replace natural gas in power

generation.

o CO2/emissions legislations may begin to reduce the use of fossil fuel ingeneral, including natural gas.

20.0 Trans-National Transportation Is Likely to Rise20.1 With the geographical distribution of natural gas being quite different from

that of the geographical spread of consuming centres, an increasing proportion

of natural gas will come to be traded across national boundaries. This

transportation will cover both pipelines as well as LNG. Pipelines are not

always feasible and are vulnerable from the security point of view. In many

areas, that could form the transit points for natural gas pipelines, the security

concerns are especially marked. It is therefore quite likely that the increase in

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the LNG trade will more than hold its ground, not only on account of basic

economics but also from security considerations. As a consequence, it is

expected that the share of LNG in global natural gas (conventional, shale,

CBM etc) will continue to show a significant rise in the coming years.

20.2 Emerging markets in South and South East Asia, Central and Latin America

are expected to experience rapid growth in gas consumption of up to 10 per

cent per annum over the next couple of decades. It is possible that both India

and China will experience a similar pace of growth in domestic demand.

21.0 Evolution of LNG Markets

21.1 Conservative estimates of project completion suggest that global LNG

capacity will grow by 30 per cent between 2010 and 2015. LNG markets may

retighten by 2015 depending on spread of new liquefaction capacity being put

in place. On the natural gas supply side, in the next 20 years unconventional

gas output is expected to grow manifold and form an important component in

the total output of natural gas.

22.0 Gas Price Setting Mechanism Differ Across Regions

22.1 The different pricing mechanisms in the world are as follows:

o North America Coal floor/residential ceiling based on powerdispatch economics- Fuel switching in power and industrial applications

sets marginal demand

o OECD Europe Residential linked long-term supply contracts - Incentivesfor residence-linked pricing aligned across stakeholders

o Asia Pacific Crude-linked long-term contracts- Security of supply iscritical

22.2 A summary of the current situation, the likely future situation and the

associated risk factors are presented in Chart-1.

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Chart 1 Pricing Mechanism Worldwide

Source

: GAIL

3.0 Some Features of the LNG market

self-balance. The current supply

2

23.1 The LNG industry has the potential to

capacity overhang is finite (existing capacity will be absorbed by 2015-2018).

Despite new players entering the market, sellers act as a club with the

largest 10 players expected to account for more than 60 per cent of capacity by

2020. Buyers have limited incentive to drive prices down, due to downstream

market structure and upstream equity participations. Sellers have a strong

disincentive to alter the price structure and kill the goose that lays the golden

egg (Asian market). Industry has a consistent history of project delays and

budget overruns. Buyers and sellers paid a heavy price for overestimating the

impact of past imbalances (e.g. 2003/04).

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CHAPTER III

Indian Gas Markets Demand & Supply Side

24.0 Introduction

24.1 In the last decade, the Indian economy has shown strong growth. Slowly, India

is gaining strategic importance globally owing to its economic growth pattern

and attractive market. After coming out successfully from the financial crisis,

the Indian economy is back on a robust growth track.

24.2 With economic growth, there will be more energy demand. This will result in

an increase share of natural gas in Indias energy basket. With a targeted GDP

growth rate of 9 per cent, Indias energy demand is expected to grow by 6.5

7.0 per cent.

24.3 The last decade also showed strong growth in the Indian gas sector. Gas is

slowly emerging as a primary source of energy for India, along with coal and

oil. The British Petroleum Statistical Review 2010, places natural gas as

accounting for about 10 per cent of Indias energy basket and this figure is

forecast to reach 20 per cent by 2025. It is also expected that by 2015, the

Indian gas market may be likely to be as large as that of Japan.

Chart 2 Composition of Indias Energy Basket

Source: BP Statistical Review 2010

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24.4 Current consumption of gas in India is around 170 mmscmd. The power sector

is the anchor customer for the gas sector, consuming 38 per cent of the total

supply while the fertilizer sector consumes around 25 per cent. The sector

wise consumption of gas in India is given in Table 3.1.

Table 3.1 Consumption of Natural Gas by Sector

Unit: mmscmd

2009/10 June 2011

Power 56.42 61.41

Fertilizers 37.37 37.74

CGD/CNG 6.54 7.90

Refineries 12.29 19.77

Sponge Iron/Steel 6.49 7.01

Petrochemicals 6.79 5.67

Other uses 11.72 17.01

LPG and C2-C3 extraction 6.52 9.18

Internal Consumption in Pipelines 2.01 2.47

Total 146.15 168.16

24.5 Although gas price have changed a lot in last two decades and are slowly

moving towards market driven price, the Indian gas market is sensitive to

price. In the last 20 years, the growth of the gas market was steady and with

improved infrastructure, local discoveries and low price level, the usage has

begun to rise rapidly. Currently, India has a substantial demand for gas that

has been estimated to rise, with estimates in excess of 370 mmscmd by

2016/17. As domestic gas discoveries are expected to be limited, the demand

supply gap is expected to continue due to non-availability of domestic gas.

25.0 Domestic Demand for Natural Gas

25.1 The consumption of natural gas and R-LNG in India has expanded rapidly. At

the margin it was, and will continue to be, a replacement for other fossil fuels

and petroleum based chemical feedstock. Historically, natural gas was

significantly cheaper than comparator petroleum fuels like motor spirit,

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naphtha, diesel and LSHS/FO. This was the case too in India and it assisted in

covering the capital cost for the older liquid fuel based plants to natural gas

use. The advent of new technology and larger plants, ensured that gas based

use came to enjoy very large efficiency and scale economies. In consequence,

it has become the preferred route for fertilizers, petrochemicals and has made

large inroads into power generation.

25.2 However, as the natural gas market has matured, the spread between the price

of natural gas and that of liquid fuels has reduced. Further, the price of liquid

fuels itself has shot up. Thus, the price of Brent crude has risen from $25/bbl

in 2002 to $50/bbl in 2005, to $117/bbl in recent months. This is an increase

of 368 per cent over the nine-year period. In the same period LNG prices in

the Asia Pacific market has gone up from $2.50 to $14.00 per mmbtu or by

460 per cent.

25.3 In the face of such sharp and steep price increase, adjustment on the user side

is not easy. This is especially so since natural gas is an intermediate good and

the decision to use it involves a commitment of large investments in the form

of fixed capital. The user is constantly facing the risk of not being fully able to

pass-on the escalating cost of the input material to the final customer. This

causes friction in decision taking and in the finalization of supply contracts.

25.4 Significant investment have already been made in the power, fertilizer,

petrochemical and other areas such that it is most likely that there will be a

sustained increase in the level of natural gas consumption in the country.

25.5 As noted previously, starting from the existing consumption level (net of I/C,

flaring etc) of about 170 mmscmd, there are additional requirements from the

power and fertilizer sectors.

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25.6 Between 2011/12 and 2012/13 an additional 12,200 MW of gas based power

capacity is expected to be commissioned which will require commensurate

additional supply of natural gas.

25.7 In the fertilizer sector 3.8 mmscmd of natural gas would be needed for the

conversion of LSHS/FO based fertilizer plants to gas based. In the next year,

or shortly thereafter, another 8.45 mmscmd of natural gas will be needed for

the change over of naphtha based fertilizer plants to gas based. Further, de-

bottlenecking and unmet demands of 4.10 mmscmd exist. In addition, there is

further possible demand from new urea projects.

25.8 Even if we were not to consider additional gas based power plants and new

gas based fertilizer plants, the total gas consumption level would approach 235

mmscmd by 2014/15. Further, sectors other than power and fertilizer would

also see growth. If we are to ascribe a modest growth of 67 per cent in these

areas of use (which may be quite conservative), the total demand for natural

gas is likely to exceed 300 mmscmd by 2014/15 and more than 370 mmscmd

by 2016/17.

25.9 It is estimated by the Department of Fertilizers that further capacity of 8

million tonnes of urea involving six projects is in the pipeline which would

require additional 14.4 mmscmd. In the power sector, further gas based

capacity of 20,000-25,000 MW is being considered which would involve an

additional gas requirement of 80100 mmscmd.

25.10 There is enormous scope for further use of natural gas in automotive vehicles

and as cooking fuel. Conversion of vehicles, especially that in the public

transport system, from diesel to natural gas not only involves direct economic

savings to the user (even at R-LNG prices), but also creates beneficial

externalities in the form of lower pollution levels. The replacement of LPG

use in the larger urban areas with piped gas is also desirable, both in terms of

comparative economics and also keeping in view the large subsidy outgo that

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LPG use presently entails. There are many other innovative uses of natural gas

such as that in combined power generation and cooling in large office

complexes, as also as fuel in factories. Bearing all this in mind, the inevitable

conclusion is that there is a large potential increase in the consumption level of

natural gas that is possible in this country, beyond even 370 mmscmd by

2016/17.

25.11 The domestic production of natural gas is significantly less than that of

consumption, being about 75 per cent of domestic consumption needs. Imports

in the form of LNG account for the balance. It is certain that over the next

several years, exploration and production efforts will result in an increase in

the availability of natural gas. However, even in the most optimistic

circumstances it is not possible to visualize a situation where increase in

domestic gas production will be able to meet incremental domestic

consumption. In fact, incremental domestic output is more likely that not to

fall considerably short of incremental domestic consumption.

25.12 The proportion of imported natural gas to total consumption is thus quite

likely to increase from the present level of 25 per cent to around 40 per cent if

not higher. Natural gas can be imported either through pipelines from

producing countries in the neighbourhood or in the form of LNG. The difficult

conditions that are prevalent in all the access points in the North West to gas

fields in Central Asia or West Asia place any immediate start up of pipeline

construction in some doubt. Likewise, the pipeline with natural gas fields in

Myanmar is also futuristic. In any case, pipeline construction takes time and

for the foreseeable 58 years (i.e. up to the end of XIIth Plan and up to 2020),

it is necessary to plan on the basis of the entirety of the incremental imports as

coming from LNG.

25.13 This would have consequences in terms of adequate handling capacity being

set up in the country as well as appropriate sourcing to be done from overseas.

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25.14 The critical issue may seem to be the price of natural gas/LNG. The fact,

however, is that energy prices are going to rise relative to other goods and

services. This is particularly true for petroleum. As things exist today, LNG

prices are linked to crude petroleum prices with a discount. This discount has

been rapidly falling over the past few years and present LNG prices in the

Asia Pacific region imply a discount of only 34 percentage points. Even

assuming no further reduction in the discount but given the fact that crude oil

prices will continue to escalate, it is hard to conceive of a situation that LNG

prices will not.

25.15 It is, of course, true that the discovery and development of non-conventional

natural gas sources shale gas, tight gas and Coal Bed Methane may work to

the advantage of the natural gas user by exercising a moderating influence on

the price. However, even in the most benign situation that can be envisaged, at

best, the implicit discount from crude may reduce somewhat from the elevated

levels presently embodied in Asia Pacific LNG prices of $14 per mmbtu. But a

return to prices of $56 mmbtu for LNG should not be envisaged. It is,

therefore, imperative that any operational plan to bear in mind that the best

possible prices in the future are going to be higher than that in the past and we

should be prepared for the adverse situation when prices are even higher.

25.16 In India, there is a particular situation where domestic coal prices have lagged

the general world wide increase in price of fossil fuels. In consequence, there

is a very large spread between the price of domestic coal and that of imported

coal and also between domestic coal and world gas prices. However, this

situation will also slowly correct. Rapid correction is not possible because of

the public policy need to moderate the consequent price in electricity tariffs.

This is the same reason why domestic natural gas prices are also lower than

Asia Pacific LNG prices, though it is at about the same level as natural gas

prices in the US and Canada.

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26.0 Future Gas Sourcing

26.1 India is pushing hard to increase its domestic gas production to cater to the

large demand. Since the creation of NELP, eight rounds of bidding have takenplace. The ninth round of bidding is currently in progress. There is consensus

that a large portion of the possible sedimentary basin has been explored.

Currently, there is prevailing uncertainty over potential from the new NELP

and CBM blocks. In addition, the government is bringing out the new Open

Acreage Licensing policy towards the end of 2011 or early 2012 which could

prove to be a discontinuity against the earlier regime. The open acreage

licensing policy will have several new features as opposed to the earlierNELP:

Flexibility of bidding throughout the year for upstream oil companies Shifts bidding of blocks from government to investors Helps manage risks better and E&P companies can evaluate the data in

a meaningful manner

26.2 This will result in building the National Data Repository (NDR) to archive all

E&P data. In addition, it will help E&P companies reduce their risk exposure

and attract international companies, that is, Shell, Exxon Mobil, and BP to the

Indian E&P space.

26.3 Domestic supply of gas will be limited and the primary producer of gas will be

Reliance and ONGC. Optimistic supply projection of domestic gas (Producer

wise) is given in the following Table 3.2 which is based on DGH data.

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Table 3.2 Optimistic Projections of Output of Natural GasUnit: mmscmd

Year ONGC OIL PSC CBM Total

2010-11 58.86 9.0 78.0 0.1 146.0

2011-12 68.74 10.4 75.5 0.4 155.0

2012-13 73.10 10.8 104.3 3.4 191.6

2013-14 75.10 11.0 106.5 5.8 198.4

2014-15 75.00 11.3 109.2 7.4 202.9

2015-16 102.00 11.6 116.3 8.6 238.5

2016-17 99.80 11.7 126.5 9.3 247.3

Source: GAIL, DGH

26.4 Indigenous gas production in India can be classified on regulatory &

contractual basis as follows: nominated fields awarded to National Oil

Companies, Small size & Medium size fields awarded to private parties, pre-

NELP discovered fields, NELP fields and CBM blocks5. As regards NELP

blocks, production has commenced from KG D6 (D1, D3 & MA). Field

Development Plan (FDP) is under implementation in GSPCs Deendayal West

block and gas production is expected from mid 2012. Further, Declaration of

Commerciality (DoC) has been approved for KG D6 satellite discoveries &

NEC 25 of RIL and of ONGCs blocks in KG & Mahanadi Basin. As regards

Coal Bed Methane (CBM) blocks, only Raniganj (South) of GEECL is

currently under production. FDP is under implementation in RILs Sohagpur

(E) & (W). Further, FDP is under review for ESSARs Raniganj (E) block

26.5 Future availability of indigenous gas (Projected) as per EGoM on 28th July,

2010 is given in the Table 3.3.

5 As regards nominated blocks given to National Oil Companies (NOCs), viz., ONGC and OIL,information regarding expected gas availability has been obtained from the NOCs themselves.Information regarding expected future production from Small size & Medium size fields, pre-NELPdiscovered fields, NELP fields and CBM blocks has been obtained from Directorate General of

Hydrocarbons (DGH)

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Table 3.3 Projected Availability of Domestic Gas

20102011 20112012 20122013 20132014 20142015 20152016

Small Size (A) 2.03 1.78 2.44 2.05 2.03 1.65

Medium Size (B) 14.31 11.62 9.55 8.21 7.29 6.85

Pre-NELP (C ) 2.11 1.83 1.39 1.19 1.15 1.15

NELP (D) 59.6 60.29 90.95 95.02 98.7 106.68

CBM (E) 0.1 0.41 3.37 5.8 7.36 8.59

ONGC Nominated Firm (F) 58.86 68.74 73.1 67.57 61.34 55.77

ONGC (Nominated) Additional

Indicated (G)7.53 13.21 15.23

OIL (Nominated) (H) 5.8 5.8 5.8 5.8 5.8 5.8

Total (Firm)(A+B+C+D+E+F+H)

142.81 150.47 186.6 185.64 183.67 186.49

Total (Optimistic)

(A+B+C+D+E+F+G+H)142.81 150.47 186.6 193.17 196.88 201.72

26.6 As per GAILs internal analysis, additional domestic gas sourcing can be in

the range of 215 mmscmd to 240 mmscmd by 2015.

Chart 3 Projected net gas production from domestic sources, 2015

Source: GAIL

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26.7 As the demand is far exceeding supply in India and there are very few new

domestic sources available, in future, additional demand can be catered to only

through LNG (unless any large domestic discovery is made) or through

transnational pipelines if and when they get constructed.

26.8 But currently, structural features existing in the closely held LNG market is

driving crude linked LNG price in an upward direction. Some of the issues

pertaining to this are:

In a commodity market where supply exceeds demand, there should beconsistent downward pressure on the market price. However, certain

structural features of the LNG market tend to protect the status quo on

pricing:

The current supply capacity overhang is finite, and is expected to beovertaken by demand by 201516.

Despite new players entering the market, seller industry concentrationremains high. The 10 largest players are expected to account for more than

60 per cent of LNG capacity by 2020

Buyers have limited incentive to drive prices down, due to downstreamtariffs and upstream equity participations

Sellers have a strong disincentive to alter the price contracts andjeopardize the pricing in the Asian market

Industry has a consistent history of project delays and budget overruns.

26.9 Buyers and sellers paid a heavy price for overestimating the impact of past

supply demand mismatches.

26.10 However, some downward pressure is expected on LNG prices on account of

factors such as unconventional gas development (Europe and Asia) and energy

efficiency measures. Other sources of gas include unconventional gas sources

like shale gas and Coal Bed Methane (CBM). In the lon

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