Oil & Gas

VIJAYANT GUPTA

RISHABH GUPTA

OIL AND GAS: SECTOR REPORT

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Table of Contents

Value Chain Analysis ............................................................................................................................. 5

Upstream ............................................................................................................................................. 5

Midstream ........................................................................................................................................... 5

Downstream ........................................................................................................................................ 6

Sector Specific Terms & Ratios .............................................................................................................. 7

Gross refinery margin (GRM)............................................................................................................. 7

Reserve Replacement Ratio (RR) ....................................................................................................... 8

Return on Capital Employed (RoCE) ................................................................................................. 8

Energy Return on Investment (ERoI) ................................................................................................. 8

Nelson Complexity Index (NCI) ......................................................................................................... 8

Enhanced Oil Recovery (EOR) ........................................................................................................... 9

BTUs ................................................................................................................................................... 9

Rig Utilization Rates ......................................................................................................................... 10

Type of Crudes .................................................................................................................................. 10

Brent-WTI Spread ............................................................................................................................. 11

Unconventional Gas .............................................................................................................................. 12

Shale Gas: Technology ..................................................................................................................... 13

Horizontal Drilling ........................................................................................................................ 13

Hydraulic Fracturing or ‘Fracking’ ............................................................................................... 13

Shale Gas in India ............................................................................................................................. 14

Coal Bed Methane (CBM) ................................................................................................................ 14

Production ..................................................................................................................................... 14

Geopressurized Zones ....................................................................................................................... 15

Methane Hydrates ............................................................................................................................. 15

Deep Natural Gas .............................................................................................................................. 15

Reserves ................................................................................................................................................ 16

Oil ..................................................................................................................................................... 16

Gas .................................................................................................................................................... 16

Exploration and Production .................................................................................................................. 16

Discoveries ............................................................................................................................................ 19

Licensing Policy ..................................................................................................................................... 21

New Exploration Licensing Policy (NELP) ...................................................................................... 21

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Open Acreage Licensing Policy (OALP) .......................................................................................... 23

Other Government Policies ............................................................................................................... 24

Privatisation .................................................................................................................................. 24

MAHARATNA STATUS ................................................................................................................... 25

OIL ......................................................................................................................................................... 25

Demand and Supply .......................................................................................................................... 25

Refineries .......................................................................................................................................... 27

Pipelines ............................................................................................................................................ 29

Crude Oil Pipeline .......................................................................................................................... 29

Product Pipeline ............................................................................................................................ 29

Retailing ............................................................................................................................................ 32

GAS ........................................................................................................................................................ 32

Demand and Supply .......................................................................................................................... 32

Gas Pipeline Infrastructure ............................................................................................................... 35

LNG ........................................................................................................................................................ 36

LNG: Supply Deals ............................................................................................................................. 37

International Pipelines .......................................................................................................................... 37

Turkmenistan-Afghanistan-Pakistan-India pipeline .......................................................................... 37

Iran-Pakistan-India pipeline .............................................................................................................. 38

Myanmar-Bangladesh-India pipeline ................................................................................................ 38

Hydrocarbon Pricing ............................................................................................................................. 39

Crude oil ............................................................................................................................................ 39

Petroleum products: ......................................................................................................................... 39

Natural Gas ....................................................................................................................................... 41

LNG .................................................................................................................................................... 41

Company Analysis: Cairn India .............................................................................................................. 42

Company Analysis: BPCL ....................................................................................................................... 43

Industry Outlook ................................................................................................................................... 46

Appendix ............................................................................................................................................... 47

International Factors Driving Crude Oil Prices .................................................................................. 47

Demand: non OECD ...................................................................................................................... 47

Demand: OECD .............................................................................................................................. 48

Supply: OPEC ................................................................................................................................. 50

Supply: Non-OPEC ......................................................................................................................... 52

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Balance .......................................................................................................................................... 53

References ............................................................................................................................................ 55

Table 1: Upstream Project Database ..................................................................................................... 20

Table 2: Oil demand and supply............................................................................................................ 27

Table 3: Pipeline infrastructure ............................................................................................................ 30

Table 4: Gas demand and supply .......................................................................................................... 34

Figure 1: Value chain of oil and gas ....................................................................................................... 7

Figure 2: Oil demand and supply .......................................................................................................... 27

Figure 3: Pipeline infrastructure ........................................................................................................... 31

Figure 4: Gas supply and demand ......................................................................................................... 34

Figure 5: Gas pipeline infrastructure .................................................................................................... 35

Figure 6: Rate chart for JCCP (Japanese crude cocktail preliminary) .................................................... 42

Figure 7: Subsidiaries and Joint ventures for BPCL ............................................................................... 45

Figure 8: World fuel consumption vs World GDP growth vs WTI crude oil prices ............................... 47

Figure 9: Non-OECD fuel consumption vs GDP growth ........................................................................ 48

Figure 10: OECD liquid fuels consumption vs WTI crude oil price ........................................................ 49

Figure 11: World fuel consumption vs World GDP growth vs WTI crude oil prices ............................. 49

Figure 12: OPEC production targets vs WTI crude oil prices ................................................................ 50

Figure 13: OPEC spare production capacity vs WTI crude oil prices ..................................................... 51

Figure 14: World liquid fuels production vs GDP vs WTI crude oil prices ............................................. 51

Figure 15: Non-OPEC liquid fuels production vs WTI crude oil prices .................................................. 52

Figure 16: Projected non-OPEC liquid fuels production ....................................................................... 53

Figure 17: OECD liquid fuels inventories vs WTI futures spread .......................................................... 54

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Value Chain Analysis

The activities of Oil and Gas sector can be broadly divided into upstream, midstream and

downstream activities.

Upstream

The upstream oil sector is a term commonly used to refer to the searching for and the

recovery and production of crude oil and natural gas. The upstream sector includes the

searching for potential underground or underwater oil and gas fields, drilling of exploratory

wells, and subsequently operating the wells that recover and bring the crude oil and/or raw

natural gas to the surface.

As the first phase in oil production, the upstream sector includes well exploration, drilling

and operation. Upstream is important because it determines supply which affects prices in the

downstream sector. The upstream sector is primarily concerned with finding and utilizing the

available petroleum supply, as opposed to the downstream and midstream sectors that are

concerned more about the demand of oil and its transportation.

Technology is the most crucial factor for in up stream’s exploration and extraction. Advances

in technology allow geologists to not only locate more oil fields, but it also allows them to

access fields that were previously inaccessible. Upstream technology is also crucial to

increase the total production of oil from existing wells. The upstream sector is where oil

companies focus for growth. This implies that the more upstream resources an oil company

has, the bigger the company is and the more profits it can generate. It is also imperative for

companies involved in upstream is calculate and plan out the rate of extraction so the reserves

do not go dry before appropriate profits have been accrued.

The upstream sector received a major boost in 1974 on discovery of Mumbai High Oil fields.

It was dominated by public sector firms. Then government introduced NELP to encourage

private sector participation. Now these companies are trying to improve oil & gas extraction

by Enhanced Oil Recovery (EOR) techniques. To increase production, new technologies like

Underground Coal Gasification (UCG), Coal Bed Methane and Exploration of Gas Hydrates

are being explored.

Midstream

The midstream sector is primarily concerned with the transportation of oil and natural gas

from the extraction site to the refineries. This sector is often included as an extension of

either the upstream or downstream sector, depending on the source. Transporting raw oil and

natural gas is a highly technical process that involves compressing the fluids to necessary

pressures in order to be transported through pipelines.

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The midstream sector is also responsible for treating raw materials in order to remove

impurities such as water vapour or hydrogen sulphide. Removing impurities and compressing

the fluids helps maximize the amount of oil and natural gas that can be transported, thus

maximizing efficiency and profits for companies are an important aspect in this sector of the

industry.

Because the midstream sector is involved with transporting large quantities of oil and natural

gas, it is imperative for companies to have a lot of awareness to help minimize pollutants that

may result from miles and miles of pipeline. Technological advances have made this a much

more efficient process, and future developments also promise to make it a much more

efficient process. Once the petroleum has been through the midstream sector and transported

to the refineries, it must undergo one last transformation before it is ready to be sold on the

market.

Downstream

The downstream oil sector is a term commonly used to refer to the refining of crude oil and

the selling and distribution of natural gas and products derived from crude oil. Such products

include liquefied petroleum gas (LPG), gasoline or petrol, jet fuel, diesel oil, other fuel oils,

asphalt and petroleum coke. The downstream sector includes oil refineries, petrochemical

plants, petroleum product distribution, retail outlets and natural gas distribution companies.

The downstream industry touches consumers through thousands of products such as petrol,

diesel, jet fuel, heating oil, asphalt, lubricants, synthetic rubber, plastics, fertilizers, antifreeze,

pesticides, natural gas & propane. All retail outlets such as gas stations are included in the

downstream sector of the industry.

This is where the efficiency of the midstream and upstream effects how much and for what

price oil can be sold. The more efficient the previous processes, the more efficient the

downstream process will be. Downstream also includes marketing, customer service and

strategic planning for the sale and distribution of finished products.

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Figure 1: Value chain of oil and gas

Source: petrostrategies.org

Sector Specific Terms & Ratios

Gross refinery margin (GRM)

It is the money a company makes by buying an unprocessed commodity and selling the

refined product. Deduct the price of crude oil from the price of the refined oil and you get the

gross refining margin. For instance, if a petroleum refinery buys crude oil for $100/bbl and

sells refined oil for $113/bbl, then $13 is the gross refiner margin. This $13 is what the

market is willing to pay the company for adding value to the crude product.

Vertically integrated oil companies, such as BP, Chevron, ExxonMobil and Shell, produce

their own crude oil. In their case, the refining margin is simply producing one barrel of

refined petroleum from one barrel of crude oil. Since several costs are shared, the margins are

higher for vertically integrated companies compared with stand-alone refineries, which buy

crude from the open market. Moreover, the more efficient companies can refine the same

crude oil at lower cost. So their margins are higher than those with old technology or poor

economies of scale. The change in refinery margins is also seasonal. For instance, in end-

March and April, prices rise because of a tightening of supplies as refiners start normal spring

maintenance and turnaround operations at various refineries. At this time of the year, refiners

are also gearing up for summer demand. That temporarily limits the availability of supply,

putting upward pressure on prices, which in turn increases refining margins until the market

balances back. Finally, margins also depend on the kind and quality of refined products that a

company can produce from the feedstock. Often, a company realises different gross margins

from its plants located in different locations/countries.

When the price of crude oil and the refined product are decided by outside forces, it can

maximise profits only by reducing costs to minimum. Attempts to source crude oil as cheaply

as possible and trying to sell the refined product at maximum price further add to margins.

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Reserve Replacement Ratio (RR)

A metric used by investors to judge the operating performance of an oil and gas exploration

and production company. This ratio measures the amount of proved reserves added to a

company's reserve base during the year relative to the amount of oil and gas produced. A

ratio of 100% means current production is sustainable, above 100% means it can grow, and

below 100% means it is likely to decline. The reserve-replacement ratio is just one method

investors should use to get an accurate picture of how well an oil company is performing.

This ratio should only be looked at in the context of other operating metrics. A high reserve-

replacement ratio achieved through organic replacement is considered better than a high

reserve-replacement ratio achieved through purchasing proved reserves.

Return on Capital Employed (RoCE)

It is the ratio of earnings before interest and taxes to capital employed. This ratio indicates the

efficiency and profitability of a company's capital investments. ROCE should always be

higher than the rate at which the company borrows; otherwise any increase in borrowing will

reduce shareholders' earnings.

Energy Return on Investment (ERoI)

This ratio of the amount of usable energy acquired from a particular energy resource to the

amount of energy expended to obtain that energy resource. When the EROI of a resource is

equal to or lower than 1, that energy source becomes an "energy sink", and can no longer be

used as a primary source of energy.

For example, when oil was originally discovered, it took on average one barrel of oil to find,

extract, and process about 100 barrels of oil. That ratio has declined steadily over the last

century to about three barrels gained for one barrel used up in the U.S. (and about ten for one

in Saudi Arabia).

Nelson Complexity Index (NCI)

Nelson Complexity Index is a measure of secondary conversion capacity in comparison to the

primary distillation capacity of any refinery. It is an indicator of not only the investment

intensity or cost index of the refinery but also the value addition potential of a refinery. The

index was developed by Wilbur L Nelson in 1960 to originally quantify the relative costs of

the components that constitute the refinery. Nelson assigned a factor of one to the primary

distillation unit. All other units are rated in terms of their costs relative to the primary

distillation unit also known as the atmospheric distillation unit.

The Nelson Complexity Index method uses only the Refinery Processing Units or the" Inside

Battery Limits " ( ISBL ) Units, and does not account for the costs of Off sites and Utilities or

the " Outside Battery Limits " ( OSBL ) Costs, such as Land, Storage tanks, terminals,

utilities required etc.

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The Nelson Complexity Index provides insight into refinery complexity, replacement costs

and the relative value addition ability and allows different refineries to be ranked. For Oil &

Gas Sector example, the Nelson Complexity Index for the Reliance refinery is 9.93 and for

the overall Jamnagar Complex is over 14.0.

Essentially a high Nelson Complexity Index as the Reliance Jamnagar Refinery is, points to

the following characteristics:

Ability to process inferior quality crude or heavy sour crudes. For example the

Jamnagar Refinery generally processes crudes which have 0.7wt% sulphur higher

compared to Indian peers.

Ability to have a superior refinery product slate comprising of high percentage of

LPG, light distillates and middle distillates and low percentage of heavies and fuel oil.

For example the Jamnagar Refinery produces no fuel oil which is unmatched by the

Indian peers.

Ability to make high quality refinery products such as Bharat 3 gasoline or diesel. For

example the Jamnagar Refinery can make Euro 3 grade gasoline unmatched by the

Indian peers.

Enhanced Oil Recovery (EOR)

Enhanced oil recovery (EOR) is the process of obtaining stranded oil not recovered from an

oil reservoir through certain extraction processes. EOR uses methods including thermal

recovery, gas injection, chemical injection and low-salinity water flooding. Although these

techniques are expensive and not always effective, scientists are particularly interested in

EOR's potential to increase domestic oil production. This is also called "tertiary recovery."

Thermal recovery uses heat to thin the oil to make it easier to extract and is popular in

California. Gas injection, common throughout the United States, can either push out oil or

thin it. CO2 EOR is considered the most promising technique. Chemical injection uses

polymers or surfactants to improve oil flow and is not common in U.S. oil production.

BTUs

Short for "British Thermal Units." This is the amount of heat required to increase the

temperature of one pound of water by one degree Fahrenheit. Different fuels have different

heating values; by quoting the price per BTU it is easier to compare different types of

energy.

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Rig Utilization Rates

Another factor that determines supply is the rig utilization rates and has a close relationship

to oil prices. Higher utilization rates mean more revenue and profits. For drilling companies,

it is important to take a close look at the company's rig fleet, because older rigs lack the

ability to drill in remote locations or to bore deep holes. Some other factors to consider are

the depth of water that the offshore rigs can drill in, hole depth and horsepower. Higher

quality rigs will have higher utilization rates, especially during weak periods. This will lead

to higher revenue growth. Though higher utilization is better, a company that is at its capacity

will have difficulty increasing revenues further.

Type of Crudes

Crude Oil is a composition of hydrocarbons and other compounds which is usually yellow or

black in colour. The viscosity and relative weight of crude oil varies and it can exist in either

liquid or solid state. It can be light or heavy, sticky or non-sticky and for some types of crude

oil, heavy flushing is required to remove it from the surfaces.

The different Types of crude oil are classified based on the standards set by American

Petroleum Institute. The properties may vary in terms of proportion of hydrocarbon elements,

sulphur content etc as it is extracted from different geographical locations all over the world.

Classification based on API:

Heavy Crude: If the API gravity of the crude oil is of 20 degrees or less, it is graded

as 'heavy'

Light Crude: Those with an API gravity of 40.1 degrees or greater than that is known

as 'light'

Intermediate: If the oil ranges between 20 and 40.1 degrees, it is graded as

'intermediate'

Classification based on the sulphur content:

Sweet : Crude oil with low content of sulphur

Sour: Crude Oil with high content of sulphur

The purity of crude oil increases or decreases based on the sulphur content as sulphur is an

acidic material.

Other major benchmarks or references are:

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Brent Blend: It is one of the largest and major Classifications of Crude oil. It is found

in the North Sea. With an API gravity of 38.3 degrees and 0.37% of sulphur, this

blend of crude oil comes from 15 various oil fields in the North Sea. Brent Blend is

refined in the United States and Gulf coasts during the times of export. Although,

Brent blend is graded as a light crude oil, it is not as light as WTI. Brent crude and

Brent Sweet Light Crude are the other classifications of Brent Blend. Due to the

presence of low sulphur content in Brent Blend, this can be easily refined and it is

best suitable for the production of gasoline and oil products.

West Texas Intermediate (WTI): Otherwise known as Texas Light Sweet. The

deposits for West Texas Intermediate are found in Texas and Mexico.

OPEC Reference Basket (ORB): When compared to Brent Blend and West Texas

Intermediate, the OPEC Reference Basket benchmark is a heavier blend. This is

sourced from

Bonny light (Nigeria)

Arab light (Saudi Arabia)

Basra light (Iraq)

Saharan blend (Algeria)

Minas (Indonesia)

Dubai Crude

The lighter version of the crude oil is priced high in comparison to the crude oils that are

classified as heavy.

Indian basket of crude oil comprises Oman-Dubai sour grade of crude and Brent dated sweet

crude in 58:42 ratio. Crude oil produced from Mumbai High (which accounts for nearly half

of India’s crude oil production) is of very good quality as compared to crudes produced in

Middle East. Mumbai High crude has more than 60% paraffinic content while light Arabian

crude has only 25% paraffin.

Brent-WTI Spread

Unusually Positive Brent-WTI spread widening

Historically, Brent has traded at a discount of about US$ 1.5/bl to WTI. However the MENA

(Middle East & North Africa) unrest has resulted in an unusual phenomenon of positive &

widening Brent-WTI spread. After trading at an average of US$ 14/bl range through Feb-

June 2011, the spread has widened to historical level of US$ 25/bl. For India, Brent prices are

more relevant as price of our imported crude is benchmarked to Brent.

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High Cushing Inventory levels & MENA unrest - the key causes

The loss of MENA crude supply along with higher European demand has resulted in Brent

prices increasing by about US$ 18/bl in last six months. On the other hand, WTI prices have

largely remained low due to high inventory levels at Cushing, Oklahoma.

Unconventional Gas

In recent years there has been an increase in unconventional gas production, specifically shale

gas in North America to increase the country’s self-sufficiency in energy resources. The

definition of unconventional gas as given by Law and Curtis in 2002 is ‘Conventional gas

resources are buoyancy-driven deposits, occurring as discrete accumulations in structural and

stratigraphic traps, whereas unconventional gas resources are generally not buoyancy-driven

accumulations. They are regionally pervasive accumulations, most commonly independent of

structural and stratigraphic traps’.

Here unconventional gas refers to tight gas, coal bed methane, shale gas and methane

hydrates. These are part of a category of frontier and unconventional oil and gas resources

that have been attracting attention recently as conventional resources are becoming exhausted

or inaccessible to non-state energy companies’. Frontier resources refer to conventional

reserves in challenging locations such as extremely deep, cold and/or very inaccessible

regions or are gas deposits which contain acid or sour gas.

The unconventional resources referred to here are nothing new and have been known about

for hundreds of years, but have only recently become economically viable and are still not

competitive with competitive gas, unless transportation costs are considered.

Coal bed methane (CBM) is methane trapped in coal deposits and is also known as coal

seam gas. Most of the methane is adsorbed to the surface.

Tight gas is trapped in ultra-compact reservoirs with a very low porosity and permeability.

Therefore, unlike conventional gas, tight gas can’t flow freely.

Shale gas is gas in the ‘source rock’, a clay-rich sedimentary rock with a low permeability,

and is either adsorbed in the shale or in a free space in pores of the rock.

Preliminary estimates of the three unconventional gas resources considered here indicate that

shale gas is the main unconventional gas worldwide. Over one half of these resources are

located in the Asia Pacific and North America. At the regional level shale gas is the main

unconventional gas resource in the regions of Asia Pacific; North America; Middle East and

North Africa; Latin America; and Europe. Coal bed methane is the main unconventional gas

resource in the former USSR and tight gas in the sub-Saharan region.

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Global estimates of the shale gas reserves present vary widely. The IEA puts the figure at 456

tcm of which 182 tcm is economically recoverable compared to 187 tcm for conventional gas.

Geologists estimate that worldwide there are over 688 shales in 142 basins.

Shale Gas: Technology

Shale gas is extracted using horizontal drilling and hydraulic fracturing or

‘fracking’.

Horizontal Drilling

During the process wells are drilled vertically to just above the known shale deposit at a

depth of 1,500 to 3,000 metres. Then the drill bit is deviated and drilled horizontally through

the shale at an angle to maximise horizontal stress for fractures.

Typically 15 to 16 wells need to be drilled to find a ‘sweet spot’ which is easily fractured and

has sufficient gas saturation to make production economical. Because the gas distribution is

uneven, currently reported extraction rates are between 4% and 6%. Therefore, more wells

are needed to produce the same volume as would be produced for conventional gas extraction.

Increasingly hydraulic drilling is being used in the United States instead of vertical or

directional drilling , despite its higher costs, because it maximises exposure to the reservoir

thus the production rate is higher. This makes shale gas extraction economical whereas

vertical drilling is not economical for shale gas.

Hydraulic Fracturing or ‘Fracking’

Productive zones that are within the well are then isolated for fracturing where water and

chemicals are injected under high pressure into the wells to fracture the rock. ‘Proppants’,

usually sand or ceramics, in the injected water solution hold the fracture crack open to

prevent their ‘healing’ and allow the continued release of natural gas. This gas is in two

forms: ‘free gas’ which is released first and ‘adsorbed gas’ on the surface of organic matter,

which is released when the pressure in the well drops.

The solution injected into the well also contains a very small quantity of additives such as

gelling agents to cause the rock to crack, biocides to kill contaminating micro-organisms and

surfactants to sterilise the well. Additives are also use to increase the efficiency of the process.

Typically these additives comprise of around 0.5% of the total injection volume. The

composition of additives used depends upon the conditions of the well such as pressure,

temperature and also the quantity of

proppant used.

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Total estimates for its operations are an average of 30 ‘fracs’ performed for each 1,000 metre

well and each ‘frac’ uses 300 m3 of water, 30 tonnes of sand and 0.5% additives in the

solution mixture.

Therefore, the process is very water intensive, which is a big issue for water-stressed states

where gas shale plays are located such as Texas. This water needs to be extracted from

aquifers or trucked in to the site on access roads.

Shale Gas in India

India remains keen to develop its unconventional gas reserves, with CBM drilling and early

production already having commenced. The development of shale gas, however, will take

longer as the government fleshes out regulations. The first shale gas licensing round is not

expected until the second half of 2013. There is significant scope for the commercial

development of Indian CBM and shale gas resources, pending the creation of an appropriate

regulatory framework and requisite investment.

ONGC started drilling its first shale gas well in the Burdawan district of West Bengal in

eastern India in September 2010. ONGC plans to drill three more shale gas wells in the

Damodar Valley, which flows through the states of Jharkhand and West Bengal, by the end

of March 2012. Initial studies by ONGC in the Damodar and Cambay basins revealed shale

gas resource potential of 991bcm and 2,548bcm respectively.

Coal Bed Methane (CBM)

CBM policy for exploration & production of CBM was formulated by the Government in

July 1997 for carrying out CBM exploration activity in the country.

Having the 3rd largest proven coal reserves and being the 4th largest coal producer in the

world, India holds significant prospects for commercial recovery of CBM. CBM resources

have been estimated to be around 4.6 trillion cubic metres (168 trillion cubic feet (TCF)) by

Directorate General of Hydrocarbons (DGH). So far, reserves of 8.385 TCF have been

established.

Production

India’s CBM production is estimated to reach 4 million standard cubic meters per day

(mmscmd) by 2016-17, as compared to the current level of 0.23 mmscmd in 2011-12.

Currently, only 1 out of 33 blocks awarded is producing gas.

So far, 4 rounds of bidding have been completed and 33 blocks covering 17,300 sq. km. of

area have been awarded. The total commercial production of CBM in the country in 2011-12

(up to February, 2012) was 74.833 mmscmd.

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In India, Essar has the largest CBM acreage in India, with about 10 trillion cubic ft of gas

across five blocks. Peak production from its Raniganj block is estimated at 3.5 million

standard cu. metres per day (mscmd) by 2014-15. RIL is expected to produce 3.5 mscmd

from its Sohagpur block by 2014 as well.

Geopressurized Zones

Geopressurized zones are natural underground formations that are under unusually high

pressure for their depth. These areas are formed by layers of clay that are deposited and

compacted very quickly on top of more porous, absorbent material such as sand or silt. Water

and natural gas that are present in this clay are squeezed out by the rapid compression of the

clay, and enter the more porous sand or silt deposits. The natural gas, due to the compression

of the clay, is deposited in this sand or silt under very high pressure (hence the term

'geopressure'). In addition to having these properties, geopressurized zones are typically

located at great depths, usually 10,000-25,000 feet below the surface of the earth. The

combination of all these factors makes the extraction of natural gas in geopressurized zones

quite complicated. However, of all of the unconventional sources of natural gas,

geopressurized zones are estimated to hold the greatest amount of gas. Most of the

geopressurized natural gas in the U.S. is located in the Gulf Coast region. The amount of

natural gas in these geopressurized zones is uncertain. However, experts estimate that

anywhere from 5,000 to 49,000 Tcf of natural gas may exist in these areas. Given that current

technically recoverable resources are around 1,100 Tcf, geopressurized zones offer an

incredible opportunity for increasing the nation's natural gas supply.

Methane Hydrates

Methane hydrates are the most recent form of unconventional natural gas to be discovered

and researched. These interesting formations are made up of a lattice of frozen water, which

forms a sort of 'cage' around molecules of methane. These hydrates look like melting snow

and were first discovered in permafrost regions of the Arctic. However, research into

methane hydrates has revealed that they may be much more plentiful than first expected.

Estimates range anywhere from 7,000 Tcf to over 73,000 Tcf. In fact, the USGS estimates

that methane hydrates may contain more organic carbon than the world's coal, oil, and

conventional natural gas - combined. However, research into methane hydrates is still in its

infancy. It is not known what kind of effects the extraction of methane hydrates may have on

the natural carbon cycle or on the environment.

Deep Natural Gas

Deep natural gas is exactly what it sounds like - natural gas that exists in deposits very far

underground, beyond 'conventional' drilling depths. This gas is typically 15,000 feet or

deeper underground, quite a bit deeper than conventional gas deposits, which are traditionally

only a few thousand feet deep at most. Deep gas has, in recent years, become more

conventional. Deep drilling, exploration, and extraction techniques have substantially

improved, making drilling for deep gas economical. However, deep gas is still more

expensive to produce than conventional natural gas, and therefore economic conditions have

to be such that it is profitable for the industry to extract from these sources.

http://www.netl.doe.gov/technologies/oil-gas/FutureSupply/MethaneHydrates/about-hydrates/about_hydrates.htm

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Reserves

Oil

The Indian petroleum ministry estimated the country’s proven and probable (2P) crude oil

reserves at 8.8bn bbl as of April 1 2010. Recovery rates at the major fields have historically

been below the industry average. ONGC is boosting recovery from Mumbai High (the largest

producing field) and other assets in its portfolio to around 40%, while offshore exploration is

throwing up some new finds, although limited largely to natural gas. Cairn India’s oil projects

in Rajasthan are significant, providing around 1bn bbl of recoverable oil. Reserves are

expected to decline steadily in the absence of major commercial discoveries.

Gas

The Indian petroleum ministry estimated the country’s proven and probable (2P) gas reserves

at 1,437bcm as of April 1 2010. The start of production from Essar Oil’s coal bed methane

(CBM) blocks in 2011 augurs well for future unconventional gas output in India, as does

BP’s 2011 investment in Reliance’s deep-water Krishna-Godavari (KG) Basin blocks, which

is likely to help boost offshore gas production.

ONGC has released its estimate for total gas volumes at its discoveries in the deep-water

DWN 98/2 block in the KG Basin. ONGC said on June 22 2011 that the block holds initial

in-place gas reserves of 101bcm.

Exploration and Production

India is the world’s fifth biggest energy consumer and continues to grow rapidly. It is the

third biggest global coal producer, but has limited supplies of oil. Oil accounts for about 30%

of India’s total energy consumption, with its share of the mix having fallen from 35% earlier

this decade. India’s 9bn barrels (bbl) of proven oil reserves (BP Statistical Review of World

Energy, June 2011) represents 0.7% of the world’s total. India’s average oil production (total

liquids) in 2010 was 910,000b/d, and estimated output was 984,000b/d in 2011. The

country’s largest-producing oil field complex is the offshore Mumbai High, operated by

state-run Oil and Natural Gas Corporation (ONGC).

In terms of gas, India currently accounts for 0.8% of global reserves and slightly more than

1% of production. The BP review puts end-2010 reserves at 1,450bcm, with 2011 production

at around 52bcm. While most of the developed gas is located in Mumbai High, major

discoveries by a number of domestic companies hold significant medium- to long-term

potential, with Reliance Industries, ONGC and state-run Gujarat State Petroleum Corporation

(GSPC) all confirming significant deepwater finds that are now under development or in

production.

17 | P a g e

The oil and gas sector is dominated by state-controlled enterprises, although the government

has taken steps in recent years to deregulate the industry and encourage greater foreign

participation. ONGC is the largest upstream-oriented oil company, dominating the

exploration and production (E&P) segment and accounting for roughly three-quarters of the

country’s oil output. The Indian government has introduced policies aimed at increasing

domestic oil production and oil exploration activity. As part of this effort, the Ministry of

Petroleum and Natural Gas crafted the New Exploration Licensing Policy (NELP) in 2000,

which permits foreign companies to hold 100% equity ownership in oil and gas projects.

Very few oilfields are currently operated by international oil companies (IOCs).

India is also trying to persuade Sri Lanka to allocate oil exploration blocks in the waters that

separate them. India is also keen to take up exploration in the Cauvery basin in Sri Lanka,

which is not far from its own offshore oil-bearing area by the same name.

Cairn India has signed an agreement with PetroSA, South Africa's national oil company, for

crude oil and natural gas exploration in South Africa. Cairn India will hold a 60 percent

interest in the block covering an area of 19,922 sq km, with PetroSA holding the remaining

interest. ONGC is also trying to enter into a partnership agreement with Russia’s Rosneft for

stake in one of the latter’s Arctic hydrocarbon projects.

Also, Oil and Natural Gas Corp. Ltd (ONGC) and Colombia’s national oil company

Ecopetrol SA have agreed to share technical expertise related to oil exploration. India has

also been invited by Cuba to partner it in the exploration of oil and hydrocarbons.

Cairn India is looking to increase Rajasthan field output from current level of 175,000 barrels

per day to 300,000 bpd (15 million tonnes per annum) and has made an application to the oil

ministry seeking permission to explore within the ring-fenced development area that contains

25 oil and gas finds.

Earlier this year, Jubilant Energy won an onland exploration block in Myanmar. The

production sharing contract for the block, covering an area of about 3600 sq km, was signed

between Jubilant, Parami Energy Development Co and Myanmar's state-owned Myanmar Oil

& Gas Enterprise. Jubilant holds 77.5 per cent participating interest in this block while

Parami Energy Development Company Ltd holds the remaining 22.5 per cent interest. The

block covers an area of about 3600 sq km and is located about 125 kms north-west of Yangon

City.

India saw its crude oil import bill swell to US$140 billion in FY 12 from US$100 billion in

FY 11, representing a 40% rise. This increase was due to rising global oil prices, declining

rupee and expanding refining capacity. The average cost of imported crude oil rose by $27

per barrel for India. India currently imports about 80 percent of its oil needs. The government

has signed exploration contracts with energy firms for 18 blocks out of the 34 blocks for

which bids were invited in the ninth round of new exploration licensing policy (NELP-

IX). This has taken the number of total blocks awarded under the nine licensing rounds since

1999 to 253. Of these, oil and gas discoveries have been made in 38 blocks. 52 exploration

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18 | P a g e

blocks in which energy firms have invested more than $12 billion have been hit by delays on

required approvals, some awarded as far back as 1999.

19 | P a g e

Presently 40 companies are participating in the upstream E&P activities in India. The mix

consists of Public Sector Undertakings (Government majority Companies-PSU's), Private

Indian Companies and International Oil companies.

Crude oil in India is produced from onshore basins in Assam, Arunachal Pradesh, Andhra

Pradesh, Gujarat, Rajasthan and Tamil Nadu along with the eastern offshore and western

offshore basins. According to BP Statistical Review of World Energy, as of December 2010,

India’s proven oil reserves amounted to 1,200 million tonnes (mt), which is about 0.7% of

total world reserves. The reserve to production ratio for India is 30 implying that, at the

current rate of production, reserves will last for another 30 years. For world, the ratio is 46.

In 2011-2012, 38.08 mt of crude oil was produced in India, a marginal increase of 1% over

the previous year. Of this, 25.05 million tonnes was produced by ONGC, accounting for 65%

of total production. The output is expected to rise by 11% to 42.30 million tonnes in 2012-13

and to 45.57 million tonnes in 2013-14 due to the output from newer fields like the Rajasthan

block of Cairn India.

India had targeted production of 206.8 million tonnes of crude oil in 2007-12, the 11th Plan

period. However, the actual production was only 176.9 million tonnes. This represented a

deficit of about 15% from the target. Under the 12th

5-year plan, production of crude oil in

India is expected to increase to 216.3 million tonnes.

The decline in production by ONGC is mainly due to the decrease in oil production from

mature fields, which have been explored for over 30 years. Decline in oil production from

ageing oilfields globally is 15%. Compared to this, the decline in production by ONGC has

been satisfactory. In order to arrest any further decline in production from ageing oil fields

and to maintain the production levels of mature fields, ONGC is now employing enhanced oil

recovery and improved oil recovery and stimulation techniques. It has resorted to capital

infusions, bringing new discovered field to production. Also, the company is undertaking

brown field development, leveraging superior technology to improve recovery factor.

Discoveries

During 2010-11, ONGC added 236.92 million tonne oil and oil equivalent gas (Mtoe) from

the 24 discoveries it made. Out of these 24 discoveries, 15 are onshore (11 new Prospects and

four new pools) and 9 are offshore (four new prospects and five new Pools). Of these, five

discoveries are in NELP blocks. Apart from the above mentioned, in August this year, ONGC

made a huge oil discovery in the D1 oilfield off the West Coast. This would also help ONGC

to boost its declining production. The new discovery has taken expected reserves of D1 from

earlier estimated 600 million barrels to 1000 million barrels. On complete development of the

field D1, the production is expected to go up to 60,000 barrels of oil per day. ONGC also

20 | P a g e

made a crude oil discovery in an exploration block in Tamil Nadu in which ONGC holds

60% stake and BPCL holds 40%.

The Oil and Natural Gas Corporation (ONGC) and Cairn India consortium has notified a

major oil and gas discovery in the KG-ONN-2003/1 onshore block in Krishna Godavari basin

off the East Coast with an estimated of 550 million barrels equivalent of in-place oil and gas

reserves. The discovery has been sent for approval to the Directorate-General Hydrocarbons

(DGH).

Natural gas reserves in Mozambique's oil-rich Rovuma Basin to the tune of 7-20 tcf were

discovered. The new discovery would make the basin's reserves 20 times the size of India's

KG-D6. Videocon and Bharat Petroleum (BPCL) hold 10% each in six blocks in the deep-

water Rovuma Basin. Due to Indian firms share, the energy security of India will also

improve. Also, Cairn India made natural gas discoveries in 2 of the wells it drilled in the sole

block granted to it by Sri Lanka government.

Table 1: Upstream Project Database

Source: Ministry of Petroleum and Natural Gas

Name Type of

Field

Companies Status Onshore/Offsho

re

Peak Oil

Output(b/d)

Peak Gas

Output(bcm)

KG-D6 Gas Reliance,

Niko

Producing Offshore NA 23.7

Deendayal(K

G-8)

Gas GSPC Developing Offshore NA NA

D-9 NA Reliance Discovery Offshore NA NA

Rajasthan Oil Cairn India,

ONGC

Producing Offshore 30,000 NA

Mumbai High Oil and

Gas

ONGC Producing

and

developing

Offshore 220,000 3.65

Tapti Oil and

Gas

BG,ONGC,

Reliance

Producing

and

developing

Offshore 7,000 4.65

http://economictimes.indiatimes.com/topic/Videocon

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21 | P a g e

Licensing Policy

New Exploration Licensing Policy (NELP)

India’s NELP, under which the government has held nine licensing rounds, is designed to

reinvigorate exploration in the country. Since its launch in 1999, the NELP scheme has been

widely praised for giving operators a transparent licensing framework and offering a seven-

year tax holiday to companies awarded licences under the NELP rounds. Some of the salient

features of the NELP include:

Freedom for operators to market crude oil and gas in the domestic market at market

determined price.

Up to 100% participation by foreign companies.

No signature, discovery or production bonus.

Income Tax Holiday for seven years from start of commercial production.

No mandatory state participation.

Biddable cost recovery limit up to 100%.

In 2008, however, Delhi withdrew the offer of a seven-year tax break on gas licences. The

move had a detrimental impact on NELP VII, which attracted bids for only 45 of the 57

blocks offered – with 12 of the 39 blocks recycled from previous rounds attracting no bids.

The following two rounds, NELP VIII and NELP IX, have also proved disappointing.

The 2005 fifth oil licensing round (NELP V) attracted significant international bidding

interest, with companies including BP, BG, Eni and Canadian independents attempting to

secure acreage. Domestic firms were once again favoured, although Cairn Energy did well,

and Italy’s Eni made its debut.

A sixth licensing round (NELP VI) took place in September 2006, at which a high level of

IOC participation was confirmed. Results of the licensing round were announced in early

2007, with ONGC once again a big winner with 25 blocks awarded – many in partnership

with IOCs.

The seventh round saw the country offer nine areas in shallow waters, 19 in deepwater and 29

onshore. The round attracted 181 bids for 12 deepwater areas, seven shallow-water areas and

26 onshore blocks, with BHP Billiton, BP, BG Group and Reliance Industries among the 96

companies to bid. BHP Billiton, in partnership with GVK Power and Infrastructure, won

drilling rights for seven deepwater areas.

ONGC won three onshore blocks, plus three deepwater blocks and seven onshore areas in

partnership with other companies, including Oil India, Indian Oil and Tata Petrodyne. BP and

Reliance jointly won a bid for a deepwater area. India may earn up to US$8bn from the

auction. Nonetheless, in many ways the round was a disappointment. 12 blocks out of the

22 | P a g e

total 57, including seven deepwater blocks, failed to get a single bid, while 19 blocks got just

one bid. In addition, majors such as ExxonMobil, Chevron, Total and Shell did not bid.

In April 2009, the Indian government launched NELP VIII, putting a record 70 offshore and

onshore blocks up for auction. The government offered 24 deepwater blocks, 28 shallow

water blocks and 18 onshore blocks in the round. It also launched its fourth CBM licensing

round, offering 10 blocks. The licensing round was a disappointment, with 76 bids received

for 36 of the 70 blocks put on offer by the government. Bids were received for only eight of

the 24 deepwater blocks on offer, while 13 shallow water blocks out of the 28 received bids.

Ten small onshore blocks attracted 37 bids, while five larger onshore blocks brought in 10

bids. Of the 10 CBM blocks auctioned, eight attracted a total of 26 bids. Reliance Industries

did not bid in NELP VIII but did bid for one block in the CBM round. The only IOCs to

participate in the round were Cairn India, BG Group and BHP Billiton, according to an oil

ministry official.

The government suggested a number of reasons for the lack of investor interest in NELP VIII.

According to VK Sibal, head of the Directorate-General of Hydrocarbons, questions were

raised over the terms of the PSCs for NELP VIII, while the gas utilisation and pricing policy

were also challenged by potential investors. Sibal said that a long-running dispute over gas

pricing between Mukesh and Anil Ambani, who split their father’s Reliance Industries

business empire between them when he died intestate, had soured IOCs’ attitude towards the

Indian investment climate.

The government launched NELP IX on October 15 2010, putting 34 onshore and offshore

blocks covering over 85,000sq km up for auction. Of the 34 blocks, 19 were in newly opened

areas, while the 15 other blocks had previously been relinquished. Of the 19 newly available

blocks, seven were in deep water, two in shallow water and 10 onshore, while one of the 15

previously explored blocks was in deep water, five are in shallow water and nine located

onshore.

BP's US$7.2bn offshore exploration deal with Reliance Industries, agreed in February 2011,

had raised hopes that IOC sentiment towards India was warming. If so, that was not on show

in NELP IX. During the auction, a consortium of Britain's BG Group and Australia's BHP

Billiton bid for and won the rights to explore a deepwater block in the Mumbai Basin, while

Cairn bid for two onshore blocks but was unsuccessful. Aside from those firms, which

already had a presence in India's upstream sector, the round was dominated by Indian

companies.

ONGC was the round's biggest winner, securing – along with its partners – the rights to 10 of

the 33 blocks awarded, including five of the eight deepwater blocks on offer, according to

Indian newspaper the Economic Times. It was the sole bidder for all 10 of the blocks on

which it bid. Reliance won two of the deepwater blocks, marking its return to the NELP

process after sitting out the NELP VIII round. Essar Oil won the Gujarat onshore block,

which attracted six bids, making it the round's most hotly contested acreage. State-run OIL

23 | P a g e

won two blocks, while a consortium of GAIL (India) and Bharat Petroleum won the rights to

four blocks. The rest of the acreage went to small private Indian explorers.

NELP IX may be the last such licensing round if the government implements the proposed

Open Acreage Licensing Policy (OALP), which would allow interested companies to bid for

any unallocated blocks at a time of their choosing without having to wait for a formal acreage

auction. India's government in March 2012 announced the results of NELP IX. Of the 34

blocks on offer, only 16 blocks have been awarded licenses. Unsurprisingly, state run oil

companies dominated the tender, obtaining operating rights for almost half of the awarded

blocks.

Also significant about the result is the unsuccessful bids for deep water blocks.

The breakdown of the 34 blocks offered under NELP IX is as follows:

8 deepwater blocks

7 shallow water blocks

11 onshore blocks

8 onshore, type S blocks

Bids for 10 of these blocks were rejected by the Cabinet Committee on Economic Affairs for

offering less than 15% of profit from output to the government. What is noticeable is the low

success bid rate for offshore blocks. 3 bids for shallow water blocks were rejected. Deepwater

bids fared worse. Of the 7 blocks bid for, not a single one was awarded a license despite

offers from consortiums led by Indian companies, ONGC and Reliance Industries.

Open Acreage Licensing Policy (OALP)

Concept of OALP was proposed in 2005. OALP for allocation of oil and gas blocks would

help bring the exploration and production business environment on a par with global

standards.

Discussions have been held between DGH, MOPNG and operators to develop consensus on

the new licensing policy. In the latest update on OALP, The Minister of State for Petroleum

and Natural Gas Shri R.P.N. Singh informed in August 2012, that the government has

initiated action to formulate Open Acreage Licensing Policy (OALP) and offer open

exploration acreages under OALP. Thus, there is no clarity on how much longer will it take

to implement OALP.

The idea behind OALP is to enable bidders to bid for blocks on offer at any time of the year

using the data for these blocks that would be made available to the bidders through the

National Data Repository (NDR).

Setting up of National Data Repository (NDR) is a pre-requisite for the new system. NDR

would provide all the geo-scientific data available in India at one place. The data will include

http://www.petroleum.nic.in/

24 | P a g e

2D and 3D seismic, geophysical and geochemical surveys of the sedimentary blocks and

results of drilled wells, if any for a particular block. Availability of data would help make the

bidders make more informed decision about the commercial viability of blocks and also

reduce their risks and costs. This would also help attract international investment in E&P

process, eventually leading to increased production of oil and gas. Thus, the quality of data is

critical to driving successful interest in the E&P space.

OALP differs from NELP in following ways:

Freedom to make bids at any point of time

Freedom to bid for any number of blocks

The size/shape of block to be dependent on the bidder

OALP to consist of two parts:

Reconnaissance phase - It would bring data position at par with NELP blocks/ develop

information on the blocks till they are evaluated to be attractive for exploration.

Exploration phase – It would be on the lines of NELP and modified from time to time.

There shall be a provision to exit after reconnaissance phase without any penalty or

reward, as long as work program is completed. The other options shall be to continue

reconnaissance phase or enter exploration.

Subsequent program at the end of reconnaissance phase (Further survey or exploration)

shall require a separate bid. To encourage proper bids, it shall be possible for a new party

to emerge winner and acquire and operate block.

Other Government Policies

Privatisation

Finance ministry data indicates the government sold small stakes in ONGC six times in 1994-

2005, and conducted three share sales for IOC in 1994-2005. The government also executed

four share sales for GAIL, one for BPCL and two for HPCL in 1992-2004. The government

earned a total of nearly INR240bn as a result, which constituted 65% of all disinvestment

share sale proceeds in the past two decades. The government also sold a 5% stake in ONGC

for Rs 12000 crore in the last fiscal quarter bringing down its stake to 69.14%.

The Indian government is planning to divest 10% of its respective holdings in IOC as part of

its plans to shrink its fiscal deficit, according to India's oil secretary S. Sundareshan. The

government currently owns 78.9% of IOC. India's oil secretary said on September 9 2010 that

the government intended to divest 10% of its 78.92% holding in IOC by January 2011, with

another 10% sale planned later in Q1 ‘11. While these plans have been delayed, the

government hopes to raise about INR100bn (US$2.15bn) through the share sale.

25 | P a g e

MAHARATNA STATUS

The government granted ONGC and Indian Oil 'maharatna' status in November 2010. The

move demonstrates the government’s efforts to increase the state-owned enterprises’

competitiveness in acquiring international oil and gas assets, particularly as India increasingly

sees itself in direct competition with China. With maharatna status, ONGC and India Oil will

be given five times more resources to spend on acquisitions and will be given more flexibility

in negotiations and adopt a more streamlined decision making process. Maharatna (‘mega

jewel’ in Hindi) status is given to the country's largest state-run enterprises. Indian companies

have repeatedly found themselves outspent and outmanoeuvred, particularly by China's large

state-owned companies, in the search for international assets, which India needs if it is to

meet soaring domestic demand. According to Bloomberg, state owned Chinese companies

spent US$32bn acquiring energy assets in 2009 compared with a lone US$2.1bn acquisition

by ONGC. While the comparison is somewhat misplaced, as India's crude import needs are

nowhere near as great as China's, the country will need to step up its international

acquisitions.

OVL has struggled to compete with China's energy E&P companies, particularly in the race

to secure African energy assets. In the hope of narrowing the gap with Chinese companies,

the Indian government directed both ONGC and Oil India to acquire one major international

asset each in the financial year starting April 2010. Furthermore, the Ministry of Petroleum

has formally asked the Finance Ministry to create a sovereign wealth fund specifically for the

purpose of overseas energy asset acquisitions, utilising funds from the country's foreign-

exchange reserves. Therefore, while ONGC continues to explore and produce hydrocarbons

in India, it recognises that India's import dependence necessitates a more aggressive

international vision.

OIL

Demand and Supply

The International Energy Agency (IEA), in its January 2012 oil market report, estimated

Indian oil consumption at 3.46mn b/d in 2011. Demand for petroleum products from the

industrial sector remained strong throughout the year, while the growth rate in gasoline

demand was relatively low, owing to price subsidy reform. Owing to a cooling (although still

growing) economy, a 3.7% oil consumption growth rate is expected in 2012, resulting in

forecast demand for 3.40mn b/d. However, this figure is set to rise above 4.08mn b/d by 2016

and reach as much as 4.95mn b/d by 2021.

Indian liquids production is estimated to have been 984,000b/d in 2011. This figure is set to

rise above 1mn b/d during 2012, on the back of rising production from the Bhagyam and

Mangala fields in the Rajasthan block. Beyond 2015, however, a y-o-y decline is expected,

26 | P a g e

pending the commercialisation of new oil discoveries. Oil imports are forecast at 2.37mn b/d

in 2012 and are set to exceed 3.0mn b/d by 2017. India’s import dependency will become

increasingly expensive. At the time of writing an OPEC basket oil price for 2012 is

US$111.47/bbl, and is expected to fall to US$107.00/bbl in 2013. For 2012, oil and gas

import costs are put at US$105.4bn, but could reach US$117.8bn in 2016 and rise to

US$159.3bn by 2021.

Over the past few years, India has stepped up exploration efforts and has taken various steps

to enhance recovery from existing oil wells – to boost domestic production and reduce

dependence on imports for 69% of its requirement. Much of state-run ONGC’s upstream

spending is directed at drilling efforts to offset declines. ONGC intends to spend INR1.64trn

(US$33bn) on capital expenditure (almost entirely upstream-focused) in the period FY2012-

17, the company's chairman, Sudhir Vasudeva, told reporters on February 1 2012. The

company is targeting crude oil production of 560,000b/d by the end of FY2013-14, compared

with just under 491,000b/d in FY2010-11. If output from ONGC's JVs and its foreign

subsidiary ONGC Videsh (OVL) is included, the latter figure would be 684,000b/d.

Besides its share in the Rajasthan block, ONGC has announced it will spend US$206.2mn on

funding its share of investment in a project to boost output at the Panna-Mukta fields off the

west coast. ONGC has a 40% stake in the JV that operates the fields – along with Reliance

and the Indian unit of BG Group, which each hold a 30% stake. The partners plan to spend

US$515.4mn on additional infrastructure and redevelopment of the fields. They expect to

recover approximately 22.8mn bbl of oil and 0.95bcm of gas.

The group has also announced plans to invest US$712mn in the first-phase development of

three marginal fields located in the Mumbai High Block. The first-phase development plans,

which call for the installation of four fixed-well platforms and the drilling of 20 development

wells, are expected to confirm that the so-called Cluster-7 fields will provide 71.3mn bbl of

crude oil and 4.52bcm of gas over a 16-year period, suggesting approximate average flow

rates of 12,200b/d of oil. Production from these fields is expected to start in March 2012,

according to the company.

India’s average oil and liquids production for 2012 is expected to be 1.03mn b/d. It is

predicted to rise to 1.11mn b/d of peak production in 2015, which is expected to decline to

1.04mn b/d by 2021. Given forecast consumption of 4.95mn b/d, implied 2021 oil imports are

put at 3.91mn b/d. Consumption of an estimated 3.28mn b/d in 2011 will rise steadily to

4.09mn b/d by 2016.

27 | P a g e

Figure 2: Oil demand and supply

Refineries

India had a total of 21 refineries in January 2011, according to the Oil and Gas Journal

Worldwide Refining Survey. The largest complex is Reliance’s merged facility at Jamnagar

(with the two refineries counted separately in the OGJ survey), which has a total capacity of

1.24mn b/d. IOC has the second largest market share, controlling 10 facilities with a total

capacity of 1.2mn b/d. The third biggest downstream player is BPCL, which has three plants

with a total capacity of 332,000b/d. The other refineries in the country are run by Mangalore

Refinery and Petrochemicals Ltd (MRPL), HPCL, CPCL and Essar.

0

500

1000

1500

2000

2500

3000

3500

4000

2009 2010 2011 2012

'oo

o b

bl/

day

Chart Title

Oil Production

Oil consumption

Oil imports

2009 2010 2011 2012

Oil Production(‘000 b/d) 877 955 984 1,029

Oil Consumption(‘000 b/d) 3,008 3,157 3,280 3,401

Oil net imports(‘000 b/d) 2,131 2,202 2,296 2,372

Oil price (US$/bbl) 61 77 108 111

Value of oil imports (US mn$) 47,408 62,196 90,094 96,516

Table 2: Oil demand and supply


28 | P a g e

Indian Oil Corporation (IOC) is the largest state-controlled downstream company, operating

10 of India’s 20 refineries (21 if the Jamnagar complex is counted as two plants) and

controlling about three-quarters of the domestic oil transportation network. Reliance opened

India’s first privately owned refinery in 1999, and has gained a considerable market share.

The end-2010 Oil & Gas Journal (OGJ) refining survey puts Indian crude distillation capacity

at 4mn b/d. Bharat Petroleum Corporation Ltd (BPCL) is considering increasing its refining

capacity through the expansion of two of its existing plants or setting up a greenfield refinery.

In a separate but related development, a new investment in private Indian company Cals

Refineries, with which BPCL has a fuel off take agreement, looks set to boost the long-

delayed project to reconstruct Germany's Ingolstadt refinery in India.

India is a net refined products exporter and will emerge this decade as Asia’s largest exporter

of refined fuels, as new projects come on stream. The Reliance-operated Jamnagar facility is

the world’s largest refining complex, with a capacity of around 1.2mn b/d. The 120,000b/d

Bina refinery was inaugurated in 2011, and a possible expansion could see its capacity rise to

150,000b/d. The 180,000b/d Bhatinda refinery could be commissioned as early as mid-2012,

while the 100,000b/d expansion of the Vadinar refinery is expected by end-2013. The

300,000b/d Paradip refinery is unlikely to come on stream until 2014.

Refinery Capacity Location Owner Jamnagar 1,240,000 Gujarat Reliance

Mumbai 240,000 Maharashtra BPCL

Numaligarh 60,000 Assam BPCL

Kochi 50,000 Kerala BPCL

Manali 190,000 Himachal

Pradesh

CPCL

Cauvery Basin 20,000 Tamil Nadu CPCL

Vishakapatnam 150,000 Andhra Pradesh HPCL

Mumbai 130,000 Maharashtra HPCL

Koyali 274,000 Gujarat IOCL

Panipat 240,000 Haryana IOCL

Mathura 160,000 Uttar Pradesh IOCL

Barauni 120,000 Bihar IOCL

Haldia 120,000 West Bengal IOCL

Guwahati 20,000 Assam IOCL

Digboi 13,000 Assam IOCL

Bongaigaon 27,000 Assam IOCL

Ambalamugal 152,000 Kerala Kochi Refineries

Mangalore 193,800 Karnataka MRPL

Vadinar 300,000 Gujarat Essar

Bina 120,000 Madhya Pradesh BharatOman

Refineries

29 | P a g e

South African coal technology specialist Sasol plans to invest around US$10bn in a project to

construct an 80,000b/d coal-to-liquids (CTL) plant in India. The plant, which Sasol is

developing with Tata in the eastern state of Orissa, is one of two such projects in the country.

According to Sasol India’s president Mark Schnell, the plant is due onstream in 2018. India's

other CTL project, which like Sasol's was approved by the government in February 2009, is

being developed by India's Jindal Steel & Power in Orissa state. The plant, which will source

coal from the Ramchandi block, will be integrated with a coal mine and a 2 Gigawatt (GW)

power station. Jindal has said the project will cost around US$8.9bn – slightly less than

Sasol's plant – and will produce 80,000b/d of fuels.

Pipelines

Pipeline network can be divided into two parts:

Crude Oil Pipeline

Currently, the crude oil pipeline network in India is around 7760 km with transportation

capacity of about 105 mmtpa. Some companies have drawn up plans for increased capital

expenditure in this segment and begun work on some pipeline to expand the network. E.g.

IOC has embarked Rs. 17 billion as capacity expenditure for enhancing its pipeline network,

including the Paradip-Haldia-Barauni crude pipeline. Cairn India has completed the 80 km

section of its Barmer-Bhogat pipeline that was scheduled for 2011.

Product Pipeline

India is a major producer of refined petroleum products. However, the network is not as

exhaustive as it should be. Pipeline transportation accounts for only 30% of the total

petroleum products transported. At present, there are 27 major product pipelines in India

totalling a length of 12,870 km with capacity to carry about 70 mmtpa of products. Currently,

a lot of expansion projects are under way.

Planned Capacity Expansion

Vadinar 100,000 Gujarat Essar

Paradip 300,000 Orissa IOCL

Bhatinda 180,000 Punjab HPCL

30 | P a g e

COMPANY CRUDE (KM) PRODUCT

(KM)

TOTAL

IOCL 4366 6286 10652

HPCL 11 2134 2145

BPCL - 1389 1389

GAIL - 1850 1850

ONGC 6106 - 6106

OIL 1193 - 1193

PIL - 946 946

TOTAL 11676 12605 24281 Table 3: Pipeline infrastructure


31 | P a g e

Figure 3: Pipeline infrastructure

Source: mapsofindia.com

32 | P a g e

Retailing

The Indian government decided on June 25 2010 to end gasoline price subsidies and allow

the market to determine prices in a bid to cut the country's subsidy-fuelled fiscal deficit. The

move marks the most significant economic reform since Manmohan Singh's United

Progressive Alliance (UPA) won the 2009 general election and will have wide-ranging

macroeconomic as well as industry-wide implications. From an industry perspective, the

decision should boost the profitability of India's largest downstream players, notably

domestic players IOC, Reliance and Essar Oil, and provides scope for growth in their

downstream operations. In its announcement, the government said it would end subsidies on

gasoline and cut them on diesel, kerosene and natural gas, though subsidies on those fuels

will remain.

The Indian government has been looking to cut the popular subsidies as strong fuel demand

has made them increasingly expensive to maintain. The country previously tried to lift the

subsidies in 2002.

Soaring energy prices, however, led to political pressures that forced the government to re-

impose the price restrictions. India spends about US$16bn a year subsidising petroleum

products, and the freeing of petrol prices could reduce the bill to around US$11.7bn,

according to petroleum secretary S. Sundareshan. Concerns over the pressure the subsidies

will place on the budget have taken precedence over inflation concerns, which had dampened

hope in the industry that the government would be able to lift the price controls.

The Indian government announced a price rise for several refined petroleum products on June

24 2011, helping to ease losses incurred by state-run refiners. Oil minister Jaipal Reddy said

diesel prices would rise by INR3/litre and kerosene by INR2/litre. Prices for cooking gas –

the most politically sensitive refined product – were raised by INR50 per cylinder (equivalent

to 14.2kg).

GAS

Demand and Supply

Gas demand is rising fast across the industrial, residential and power sectors. Consumption

has risen more than 160% since 1995. Average annual demand growth of at least 6% is

forecast over the next several years, accelerating as domestic field development and LNG

import deals make more gas available.

The 2012 gas production is estimated to be around 55bcm.Total gas consumption is predicted

to be around 91.5bcm in 2016, up from an estimated 71.1bcm in 2012. By 2021, demand is

put at 128.3bcm, requiring imports of 43.3bcm.

33 | P a g e

There are high hopes for the offshore KG Basin, which the former director-general of the

regulator DGH claimed could produce up to 44bcm annually. Reliance is investing US$5.2bn

in the development of KG Basin fields. It started producing gas from deep water Block D6 in

the KG Basin in Q1 ‘09. BP’s farm-in agreement with Reliance, originally signed in 2011,

includes the D6 block, and hopes are high that the UK major’s deep water expertise will

allow Reliance to quickly boost output.

ONGC is committing to a US$5bn development plan for the KG Basin assets, in the wake of

Reliance’s US$8bn programme. ONGC has drawn up a US$5bn proposal to produce more

than 9bcm of gas per annum from its finds in the KG Basin by 2013. The plan also envisages

producing around 8,000b/d of oil from some of these fields. ONGC’s production estimates

are expected to increase once its ultra-deepwater finds, further east of its current acreage,

come into play. These are expected to yield anything between 56bcm and 400bcm of gas.

Considerably greater investment will be required to confirm and develop these resources. For

the existing KG Basin discoveries, ONGC has increased its reserve and production estimates.

Originally, it had projected pumping 4.4-5.5bcm annually. The latest plan, submitted to the

regulator for approval, puts the reserves of the present acreage at 180bcm. ONGC will

develop the discoveries in parts of the KG-DWN-98/2 Block, along with other fields on

adjoining acreage.

ONGC has estimated that the development of three western offshore fields will add about

15Mcm/d to India's gas production over the next three or four years. The three fields – B-12,

C-23 and C-24 – are estimated to have total gas reserves of 97.2bcm and recoverable reserves

of 42bcm, according to Pande. Located among the Daman Offshore fields, the three were

discovered in 2007. To handle their output, ONGC intends to build a new gas processing

facility in the state of Gujarat, for which land acquisition is already under way, according to

Pande. The three fields are north of the prolific Bombay High, Mukta, Panna and Bassein

fields, and are just south of the BG Group-operated Tapti block. Pande estimated ONGC's

current natural gas production from Bombay High and nearby fields at 32-35Mcm/d,

equivalent to an annualised 11.7-12.7bcm.

GSPC has received approval from the DGH to develop the Deen Dayal gas field in the KG

Basin. The field, which is estimated to hold reserves of around 56.6bcm, was discovered in

2005. It is located in Block KG-OSN-2001/3 off the coast of Andhra Pradesh in the Bay of

Bengal. After GSPC completed its minimum work programme at the field in November 2008,

the company submitted a development plan to the DGH in late-June 2009.

At the time, when GSPC submitted the development plan, the company’s director general,

VK Sibal, told Indian newspaper the Business Standard that GSPC was planning to drill 15

wells at the block, with first production expected in 2012. Gas production from Deen Dayal is

expected to reach an annualised 2.1- 3.1bcm. The field covers an area of around 125sq km

and is located in the southern part of the block.

34 | P a g e

ONGC has decided to allow GAIL to market gas from its operated offshore C-series field,

India's Business Standard reported on December 9 2010, quoting an unnamed ONGC source.

C-series is a marginal gas field located in the Tapti Daman Block 60km off India's Arabian

Sea coast. Eight producing wells have been drilled at C-series, which was developed by

ONGC at a cost of INR31.95bn (US$690mn). Initial gas output of 800,000 cubic metres per

day was to rise to 3Mcm/d within a year of the start of production, which was delayed from

December 2009 to April 2010. The government has agreed to allow ONGC to sell gas to

GAIL at a price of US$5.25/mn British Thermal Units (BTU) for gas produced through to

March 2014, comparable with the US$5.70/mn BTU price it charges for gas from the nearby

offshore Panna-Mukta-Tapti fields.

2009 2010 2011 2012

Gas proved reserves(tcm) 1 1 1 1

Gas production(bcm) 41 52 52 55

Gas consumption(bcm) 53 64 68 71

Net gas imports(bcm) 12 12 16 16

Value of gas imports(US

$mn)

3,840 4,809 8,406 8,928

Table 4: Gas demand and supply


Figure 4: Gas supply and demand

0

10

20

30

40

50

60

70

80

2009 2010 2011 2012

BC

M

Chart Title

Gas production

Gas consumption

Gas imports

35 | P a g e

Gas Pipeline Infrastructure

India has a network of around 12,000 km of natural gas pipeline, while 12,000 km of

pipelines are under construction. Details of pipeline transmission network are given below:

GAIL: 8000 km

Gujarat State Petronet Limited (GSPL): 2000 km

Reliance Gas Transport Infrastructure Limited (RGTIL): 1400 km

Assam Gas Company Limited (AGCL): 500 km

Figure 5: Gas pipeline infrastructure

Source: Gail

India is aiming to have a National Gas Grid of 30,000 km by 2017, with a capacity of 875

million standard cubic meters per day (mmscmd). Currently, the gas pipelines have a capacity

to transport 230 mmscmd of gas.

Petroleum and Natural Gas Regulatory Board (PNGRB) plans to bring 300 cities and towns

under the City Gas Distribution (CGD) as a part of which piped natural gas for cooking and

CNG for the transport sector are being supplied. Currently, 51 cities are covered by CGD.

http://economictimes.indiatimes.com/topic/Petroleum%20and%20Natural%20Gas%20Regulatory%20Board

36 | P a g e

The network density for natural gas pipeline is quite low in India – pipeline length to country

area ratio is 0.003 km/square km as compared to 0.06 for USA, 1.17 for UK, 1.24 for

Germany and 0.02 for Bangladesh.

LNG

Data from the Indian petroleum ministry’s petroleum planning and analysis cell (PPA)

indicates LNG imports were 7.96mn tonnes in FY2008-09, 8.92mn tonnes in FY2009-10 and

8.86mn tonnes in FY2010- 11. In the period April-November 2011, India imported 6.75mn

tonnes of LNG.

India currently has two functioning LNG terminals, giving it a total import capacity of

13.6mn tonnes per annum (TPA). The larger of these, the 10mn TPA (14bcm) Dahej terminal

in Gujarat state, started receiving LNG shipments in January 2004. The terminal is owned by

Petronet, a consortium of BPCL (12.5%), GAIL (India) (12.5%), IOC (12.5%), ONGC

(12.5%), GDF Suez (10.0%) and the Asian Development Bank (5.2%), with the remaining

34.8% publicly held. Petronet imported 5mn TPA (6.9bcm) of LNG from Qatar’s RasGas in

2009, a volume that was contracted to increase to 7.5mn tpa (10bcm) in 2010.

India’s second LNG terminal started operations in April 2005 and is located near Surat in

Gujarat state. The facility is owned by Hazira LNG, a JV between Shell (74%) and Total

(26%). The facility had an initial throughput capacity of 2.5mn tpa, with the option of

expanding to 5mn tpa. Current capacity is thought to be 3.6mn tpa (5bcm). A third terminal,

the long-delayed Ratnagiri plant, will have an initial capacity of 1.1mn tpa (1.5bcm).

Petronet is also constructing another terminal at Kochi in the southern state of Kerala, which

is expected to come onstream in July 2012 with a capacity of 2.5mn tpa (3bcm). An

expansion of the terminal to 5mn tpa was approved in 2011. Petronet had been receiving 5mn

tpa of LNG from Qatar’s RasGas under a long-term contract, with volumes rising to 7.5mn

tpa in 2009. In January 2009, India offered Qatar a 10% stake in Petronet LNG in return for

supplying it with an additional 18 LNG cargoes over the year and agreeing to a long-term

LNG contract to supply the Dabhol power plant in Maharashtra.

The operator of a port on India's eastern coast is looking to build an LNG import terminal,

Indian business publication Livemint reported on June 13 2011, quoting two unnamed

sources familiar with the company's plans. Dhamra Port (DPCL), the operator of the

eponymous port in India's Orissa state, estimates the project will cost INR30-35bn (US$670-

780mn), although an estimated completion date was not disclosed. DPCL has apparently

sought dredging cost estimates from Dutch and Belgian firms Dredging International, Van

Oord Dredging and Marine Contractors and Jan de Nul, unnamed executives from these firms

confirmed to Livemint. DPCL has also reportedly started discussions with India's largest

LNG importer, Petronet LNG, which could see the company build and operate a

37 | P a g e

regasification facility at Dhamra. A Petronet PR official said only that his firm 'may' set up a

LNG terminal in Orissa, without naming Dhamra.

LNG: Supply Deals

As of late 2011, India and Qatar had yet to strike a deal on a mutually agreeable gas price for

an additional supply of 3-4mn tpa of LNG. Petronet imports about 7.5mn TPA from Qatar

under a long-term agreement, but wanted an additional 2-3mn TPA, while GAIL India sought

an additional 1mn TPA from the Gulf state. The supplies would be part of a long-term deal

intended to benefit Petronet's Dahej and Kochi regasification terminals, as well as for the

Ratnagiri terminal owned by Ratnagiri Gas and Power Pvt Ltd (RGPPL).

Russia's Gazprom has signed its fourth LNG supply deal with an Indian firm. The state-run

gas producer said on July 20 2011 that it had signed a memorandum of understanding (MoU)

with IOC to supply up to 2.5mn TPA of LNG over 25 years. The deal with IOC follows

similar LNG supply deals, which were signed in June 2011 with three other Indian

companies: Petronet LNG, GSPC and GAIL (India). Those deals were for the same quantity

and period. A Financial Times source close to Gazprom told the UK newspaper that the LNG

cargoes to be supplied under these agreements would be sourced from the proposed

Shtokman LNG project in the Barents Sea. Gazprom said on July 20 that IOC could be

supplied by the Sakhalin LNG project, although the statement did not rule out Shtokman as a

supply source. Britain's BG Group has signed a heads of agreement (HoA) for a 20-year deal

to supply GSPC with 3.45bcm per annum of LNG. Sales could start as early as 2014 with gas

supplied from BG's numerous projects across the globe.

GSPC plans to commission a new LNG terminal with a capacity of 5mn tpa at Mundra, in

Gujarat, by 2016. The announcement was made by the state's principal secretary for energy

and petrochemicals, D. J. Pandian, on March 19 2012. The project is expected to cost

INR40bn (US$800mn) and will be 50% owned by GSPC, with another 25% in the hands of

the Adani Group. Essar Group held the remaining 25% stake before pulling out of the project.

Pandian commented on the withdrawal saying: 'In the next 6- 12 months, we will look for a

third partner after completing a certain level of work.

International Pipelines

Turkmenistan-Afghanistan-Pakistan-India pipeline

The agreement for TAPI pipeline, also known as Trans Afghanistan pipeline was finally

signed between India, Pakistan, Afghanistan and Turkmenistan in May this year. the $7.6-

billion gas pipeline will have a capacity to carry 90 million metric standard cubic metres a

day (mmscmd) of gas for a 30-year period and is likely to become operational by 2018. India

38 | P a g e

and Pakistan would get 38 mmscmd each, while the remaining 14 mmscmd will be supplied

to Afghanistan.

India would be paying 50 cents per million metric British thermal unit (mmBtu) as the transit

fee to Pakistan and Afghanistan for the gas. It will enter India at Fazilka, near the India-

Pakistan border.

Currently, negotiations for price are going on, but India is expected to pay almost

$13/mmBtu ($9.7/mmBtu to Turkmenistan, 50 cents/mmBtu to Afghanistan and Pakistan as

transit fees and $1.83/mmBtu as transportation charges), which is lower than the $16/mmBtu

paid for imported LNG, but higher than domestically produced gas at $4.20/mmBtu.

However, doubts remain over the viability of the pipeline due to security issues, funding for

the pipeline and the ability to provide uninterrupted supply for 30 years.

Iran-Pakistan-India pipeline

The project has failed to take off. India has been reluctant to join the pipeline due to security

issues in Pakistan and the opposition of USA to the pipeline. It was expected to transport 30

million metric cubic metres of gas per day, once completed.

Myanmar-Bangladesh-India pipeline

This is another pipeline which has failed to take off. It was envisaged in 2005, but the failure

to agree on certain conditions between India and Bangladesh led to eventual shelving of the

project. However, previous year has seen a renewed interest in the project.

39 | P a g e

Hydrocarbon Pricing

Crude oil

The price of crude oil in India is determined based on the ratio of its composition of Dubai

and Oman for Sour grades and Brent for sweet grade. For 2011-12, this ratio stood at approx

65.2:38.4. The increase in the capacity of Indian refineries has resulted in their ability to

process more of Oman and Dubai grade oil, which are sourer and have higher sulphur

content. As a result, their weightage has increased from 58% in overall basket to 65 currently.

Compared to Brent, these Oman and Dubai grades trade at around $2-3 less. Thus, it has

marginally decreased the cost of India’s crude oil basket.

Petroleum products:

For determining the price of petroleum products (with the exception of diesel, kerosene and

LPG), Trade Parity Pricing (TPP) is followed. Trade Parity Price (TPP) consists of 80% of

Import Parity Price (IPP) and 20% of Export Parity Price (EPP). For this purpose, EPP

comprises of Free-on-Board (FOB) price of the product plus Advance license benefit as per

Foreign Trade Policy. The 80-20 ratio is based roughly on India’s import-export ratio for

crude oil.

Export Parity Price (EPP) represents the price which the oil company can realize on export of

their products at ex-Indian ports. Oil Marketing Companies compute EPP as Free on Board

(FOB) price of the product plus benefit of duty free import of crude oil, known as Advance

License Benefit.

Import parity price (IPP) means the price that the actual importer would pay for the product

in case he would have actually imported the same at the respective ports in India. The

elements considered in the IPP are as under:

(i) FOB (free on board) price of product at Arab Gulf.

(ii) Ocean freight from Arab Gulf to respective Indian ports

(iii)Customs Duty at applicable rates

(iv)Insurance charges

(v) Ocean Loss, Port dues

(vi)Landed cost at port = sum of the above element

The price so obtained is called refinery gate price. This is the price at which the refineries sell

products to the marketing companies

40 | P a g e

Oil Marketing companies then sell the petroleum products to consumers at retail selling price

determined by the Government. The Retail selling prices among other components include

taxes and duties by Central and State Government. Considering the inflationary impact of

increase in prices of sensitive petroleum products, the price is moderated by the Government

which results in under-recoveries in OMC.

Based on Nov 11 data, taxes and duties by Central and State Government account for 40%

and 18% of cost of petrol and diesel respectively. The comparative figures for USA are 14

and 15 percent respectively, while for Pakistan they are 28 and 27 percent respectively.

41 | P a g e

Natural Gas

Gas prices have been determined under APM for more than two decades. Here again a dual-

pricing strategy is followed, where the price of gas produced by PSU is regulated while that

of JVs/private companies is deregulated. The price charged from consumers in the power &

fertilizer sectors was raised from $1.79 per mmBtu to $4.2 per mmBtu. For consumers in

sectors such as steel and petrochemical, the price charged is $ 5.25 per mmBtu. The price of

gas for private companies/Jvs varies in the range of $4.2-$12 per mmBtu. The former applies

to gas from Krishna-Godavari (KG) basin and the latter is for CBM gas.

LNG

The Japan Customs-cleared Crude (JCC) is the average price of customs-cleared crude oil

imports into Japan (formerly the average of the top twenty crude oils by volume) as reported

in customs statistics; nicknamed the "Japanese Crude Cocktail".

It is a commonly used index in long term LNG contracts in Japan, Korea and Taiwan, and

replaced the Government Selling Price of crude oil as the standard index.

The data to calculate JCC is published by the Japanese government every month. This is the

raw and crude oil import prices in yen per kilolitre, the dollar yen exchange rate and the total

Japanese imports of all commodities for the month. JCC prices are available from the

Petroleum Association of Japan.

The data is calculated by using crude oil import data from Ministry of Finance Japan. The

formula is Total crude import value ('000 Yen)/Total crude import quantity (kiloliters) x 1000.

The data is updated on a monthly basis and subject to revision by MOF Japan. The data is

subjected to two-month lag.

http://www.enotes.com/topic/Customs

http://www.enotes.com/topic/Crude_oil

http://www.enotes.com/topic/Japan

http://www.enotes.com/topic/LNG

http://www.enotes.com/topic/Korea

http://www.enotes.com/topic/Taiwan

http://en.wikipedia.org/wiki/Government_Selling_Price

http://www.enotes.com/topic/Petroleum_Association_of_Japan

42 | P a g e

Figure 6: Rate chart for JCCP (Japanese crude cocktail preliminary)

Source: www.bloomberg.com

Company Analysis: Cairn India

More than any other company, Cairn helped turned the

spotlight on India’s upstream sector and provided the

government with hope of substantial domestic oil

production even after mature fields are depleted.

With significantly more than 2bn bbl of oil shown to be in

place and plenty of upside potential, Cairn’s new prospects

can be expected to deliver some 120,000b/d. Unexplored

prospects, upside in the recent finds and higher recovery

rates suggest that reserves and production targets are

conservative. Cairn agreed to sell its Indian subsidiary to mining concern Vedanta Resources,

with cabinet approval received in January 2012. In January 2012, the Cabinet Committee on

Economic Affairs (CCEA), headed by Prime Minister Manmohan Singh, approved Vedanta

Resources’ purchase of Cairn Energy's Indian business for US$8.48bn. The deal was

conditionally cleared in June 2011, after ONGC, Cairn India's partner in the onshore

Rajasthan oil fields, said it was satisfied that issues regarding royalty and cess payments had

been addressed.

The planned sale of Cairn Energy’s 40% stake in Cairn India to Vedanta, announced in

August 2010, was first considered by the CCEA in April 2011 and was approved in June

48,000

50,000

52,000

54,000

56,000

58,000

60,000

62,000

64,000

66,000

68,000

Feb Mar Apr May Jun Jul

Ye

n/K

ilolit

reJCCP

JCCP

STATISTICS (FY ’12) Year of Incorporation 2006

Income 12,722 cr

Profit 7,937 cr

Net Worth 48,292 cr

Operating Profit Margin 78.02%

RONW 16.43%

CAR 2.49

43 | P a g e

2011 with certain preconditions. Cairn and Vedanta complied with all the preconditions and

concluded the transaction in December 2011. However, it still needed the approval of the

cabinet.

Cairn India is among the most significant foreign companies active in India’s upstream sector.

The company operates the largest producing oil field in the Indian private sector and has an

interest in 15 blocks in the country. The company’s holdings in eastern India include Ravva

blocks PKGM-1 (22.5%), KG-OS/6 (50%) and KG-DWN-98/2 (100%), with the last two

located in the offshore KG Basin. In western India, Cairn holds stakes in CB/OS-2 (50%) and

RJ-ON-90/1 (100%). The Lakshmi field in Block CB/OS-2 produced an average of

10,802boe/d in 2003, which is sold to customers in Gujarat State.

ONGC and Cairn have started production at the Bhagyam field in the Block RJ-ON-90/1 in

Rajasthan. The companies are planning to ramp-up production to 40,000b/d of oil. Cairn

Energy India has discovered 57m of gross hydrocarbon pay with its Nagayalanka-SE-1 well

in the Krishna Godavari Basin. The well is located in the KG-ONN-2003/1 block and

encountered hydrocarbons in the Cretaceous sandstone. During a test the average flow rate of

the well was recorded at 70b/d of oil and 17 thousand cubic metres per day (mcm/d) of gas.

Cairn is the operator of the block, with a 24% stake, working alongside Cairn India Ltd with

25% and ONGC with the remaining 51%.Cairn India's strategy (prior to the takeover by

Vedanta) was to establish commercial reserves from strategic positions in high potential

exploration plays in order to create and deliver shareholder value. In the implementation of

this strategy, Cairn India focused on material positions that were capable of providing

significant growth through exploration.

Company Analysis: BPCL

Bharat Petroleum Corporation Ltd. is an integrated oil refining, exploration and marketing

company with Navaratna PSU status. Known as Burmah Shell before government takeover in

1976, it started primarily as downstream company, specializing in refining and marketing

operations.

The company specializes in the refining, processing, and distribution of petroleum products.

It produces a range of petroleum products, such as gasoline, diesel and kerosene, liquefied

petroleum gas, automotive and industrial lubricants, fuel oils and aviation fuels. The

company distributes its product through its retail network.

For 2011-12, BPCL has been ranked 225 in the Fortune global 500 rankings. Off-late, BPCL

has started diversifying in order to de-risk its dependence on fuel sales and reduce its

exposure to under-recoveries. It intends to double its profits by 2017 and venturing into the

Exploration and Production forms a key part of achieving this target.

44 | P a g e

Profit After Tax for BPCL rose 36%, from about 164,000 crores in 2010-11 to 222,000 crores

in 2011-12. Being an oil marketing company, it depends for its profits upon realization of

funds from government for subsidies given by the company. A better idea about its

performance is achieved through refinery throughput and market sales volume. The refinery

throughput for the company has been increasing at a rate of more than 5% for last 2 years.

However, the proportion of indigenous crude has gone down in total throughput, both in

absolute terms and percentage wise. The market sales have also increased over the previous

year at the rate of 6%. The market sales are composed of primarily retail customers. Other

components of market sales for BPCL include LPG, aviation fuel, city gas distribution.

So far, BPCL has been showing positive results on exploration front. It has made oil and gas

discoveries in Brazil and Mozambique respectively, and expects to start supplying from them

within 5 years. Compared to other oil marketing companies like HPCL and Indian Oil, BPCL

has better self sufficiency in terms of sales due to higher refining capacity. Also, exports

which are free from price regulation form 8% of BPCL’s total sales compared to 5% for

HPCL.

BPCL currently has refineries in Mumbai, Kochi and Bina with a combined capacity of 27.5

million metric tonnes per annum (MMTPA). It also has a subsidiary, Numaligarh refinery

with a capacity to process 3 MMTPA. BPCL is currently planning to expand its Kochi

refinery by 63%, by December 2015 and upgrade the refinery to process cheaper, high-

sulphur crude to improve margins and products. The Rs 14,225-crore expansion and up-

gradation project will see the southern India-based refinery processing 15.5 MMPTA. BPCL

is also planning to increase the capacity at the Bina refinery to 9 MMPTA from 6 MMPTA.

On the exploration front too, BPCL is proving to be a success. BPCL has a 10% stake in

blocks off the Mozambique coast, where huge gas reserves were discovered earlier this year.

Besides this, Bharat Petro Resources (BPRL), a fully owned subsidiary of Bharat Petroleum

Corporation (BPCL), successfully completed the exploration program in blocks in Cauvery

Basin in Tamil Nadu. BPRL currently has participating interest in 26 exploration blocks. Of

these, 11 blocks are in India and 15 are abroad. Besides India, BPRL has blocks in Australia,

Brazil, East Timor, Indonesia, Mozambique and the United Kingdom.

A flowchart depicting its subsidiaries and joint ventures alongwith its various business

operations is given below.

http://economictimes.indiatimes.com/topic/Mozambique

45 | P a g e

Figure 7: Subsidiaries and Joint ventures for BPCL

BPCL

SUBSIDIARIES

UPSTREAM

Bharat PetroResources

REFINING

Numaligarh Refinery Ltd

JOINT VENTURES

REFINING

Bharat Oman Refineries Ltd.

CITY GAS DISTRIBUTION

Sabarmati Gas Limited

Maharashtra Natural Gas

Limited

Central UP Gas Limited

Indraprastha Gas Limited

LNG

Petronet LNG Limited

PIPELINES

Petronet CCK Limited

ALTERNATE FUELS

Bharat Renewable Energy Ltd.

INTO PLANE FUELING

Delhi Aviation Fuel Facility (P)

Ltd

Bharat Stars Services Pvt Ltd

TRADING ACTIVITIES

Matrix Bharat Marine Services

Pte Limited

46 | P a g e

Industry Outlook

India’s average oil and liquids production for 2012 is expected to be 1.03mn barrels

per day (b/d). It is predicted to rise to 1.11mn b/d of peak production in 2015, which

is expected to decline to 1.04mn b/d by 2021. Given forecast consumption of 4.95mn

b/d, implied 2021 oil imports are put at 3.96mn b/d. Consumption of an estimated

3.28mn b/d in 2011 will rise steadily to 4.09mn b/d by 2016.

Gas demand is rising fast across the industrial, residential and power sectors.

Consumption has risen more than 160% since 1995. Average annual demand growth

of at least 6% is forecast over the next several years, accelerating as domestic field

development and liquefied natural gas (LNG) import deals make more gas available.

2012 gas production will be around 55bn cubic metres (bcm). We are predicting total

gas consumption of around 91.5bcm in 2016, up from an estimated 71.1bcm in 2012.

By 2021, demand is put at 128.3bcm, requiring imports of 43.3bcm.

Growth in near-term oil production is expected from the Rajasthan block, while we

see gas production in the KG Basin recovering following BP’s farm-in with Reliance.

Greater development of offshore and unconventional gas resources should result in a

rise in gas production, although this rise will not be enough to reduce LNG imports,

which will also rise in line with demand.

In March 2012, India's government announced the results of the NELP IX licensing

round, almost a year since its conclusion. Of the 34 blocks on offer, only 16 blocks

have been awarded licenses. State run oil companies dominated the tender, obtaining

operating rights for almost half of the awarded blocks. Also significant is the number

of unsuccessful bids for deepwater blocks. India could hold its first shale licensing

round by end-2013, according to Prime Minister Manmohan Singh. On March 23

2012, he said: 'The mapping of India's shale gas resources has been undertaken and

we are working to put in place a regulatory regime for licensing rounds by end-2013.

India’s refining segment will enjoy rapid expansion over the coming decade, with

new projects adding to the country’s already-large refining capacity. India is set to

overtake Singapore as Asia’s top exporter of refined fuels over the forecast period

(2011-21).

India’s import dependency will become increasingly expensive. At the time of

writing we assume an OPEC basket oil price for 2012 of US$111.47/bbl, falling to

US$107.00/bbl in 2013. For 2012, oil and gas import costs are put at US$105.4bn,

but could reach US$117.8bn in 2016 and rise to US$159.3bn by 2021.

47 | P a g e

Appendix

International Factors Driving Crude Oil Prices

Demand: non OECD

Past decade has seen a rise in oil consumption by non-OECD (Organization of Economic

Cooperation and Development) countries. Their consumption increased by more than 40% on

the back of rapid economic growth of China and India and other Asian countries.

Figure 8: World fuel consumption vs World GDP growth vs WTI crude oil prices

Source: EIA Energy Outlook, Thomson Reuters

Many manufacturing processes consume oil as fuel or use it as feedstock, and in some non-

OECD countries, oil remains an important fuel for power generation. Another reason has

been rise in the number of vehicles on the road, owing to increasing per capita income.

Structural conditions in each country's economy further influence the relationship between oil

prices and economic growth. Developing countries like China have a greater proportion of

their economies in manufacturing industries, which are more energy intensive than service

industries. China has now become the largest energy consumer and second largest oil

consumer in the world. According to EIA estimates, almost all the net increase in oil

consumption in the next 25 years will come from non-OECD countries.

Apart from economic activity, oil use also depends on energy policies. Many developing

countries keep the market prices under check, which inhibits consumer response to market

price changes.

48 | P a g e

Figure 9: Non-OECD fuel consumption vs GDP growth


Demand: OECD

The Organization of Economic Cooperation and Development (OECD) consists of the United

States, much of Europe, and other developed countries. These countries account for 53% of

oil consumption but have a lower oil consumption growth compared to non-OECD countries.

In fact, previous decade has seen a decline in oil consumption by OECD countries.

Developed countries have a higher vehicle ownership per capita. Thus, oil use by

transportation sector as a percentage of total oil consumption is higher for OECD countries

compared to non-OECD countries; OECD automobiles market is also more mature and

slower-growing.

Many OECD countries have higher fuel taxes and policies to encourage the fuel efficiency

and use of cleaner fuels like bio fuels. This tends to slow the growth in oil consumption even

in times of strong economic growth. Also, OECD countries have a larger service sector

compared to manufacturing sector. Thus, strong economic growth in these countries may not

have the same impact on oil consumption as it would in non-OECD countries.

49 | P a g e

Figure 10: OECD liquid fuels consumption vs WTI crude oil price


OECD countries provide fewer subsidies and thus change in oil prices are more pronounced

for the end consumers. Thus, expectations of change in future oil prices also affect

consumers' decisions regarding vehicle purchases and transportation mode. If prices are

expected to remain high or increase in the future, more consumers may decide to purchase

more fuel efficient vehicles or use public transportation. Decisions like these help to reduce

future oil demand and to moderate expected price increase.

Figure 11: World fuel consumption vs World GDP growth vs WTI crude oil prices

50 | P a g e


Supply: OPEC

An important factor influencing the oil prices is Organization of the Petroleum Exporting

Countries (OPEC). It seeks to actively manage oil production in its member countries by

setting production targets. OPEC countries produce 40 percent of the world's crude oil and

exports represent about 60 percent of the total petroleum traded internationally. Saudi Arabia

happens to be the largest oil producer within OPEC and the world's largest oil exporter. In

face of reduction of crude oil production targets by OPEC, prices tend to increase.

Figure 12: OPEC production targets vs WTI crude oil prices


The extent of utilization of their production capacity gives an indication of tightness of global

oil markets. EIA defines spare capacity as the volume of production that can be brought on

within 30 days and sustained for at least 90 days. Saudi Arabia historically has had the

greatest spare capacity. Saudi Arabia keeps more than 1.5 - 2 million barrels per day of spare

capacity on hand which is managed according to market conditions.

51 | P a g e

Figure 13: OPEC spare production capacity vs WTI crude oil prices


The level of spare capacity of OPEC also indicates world oil market's ability to respond to

potential crises that may reduce oil supplies. Thus, oil prices tend to include a rising risk

premium when OPEC spare capacities are at a low level. Markets also get influenced by

geopolitical events taking place between OPEC countries. Member countries often do not

adhere to production targets in order to generate more revenues. This influences oil prices.

Also, natural gas liquids (NGLs) are not included in OPEC production allocations.

Figure 14: World liquid fuels production vs GDP vs WTI crude oil prices

52 | P a g e


OPEC also adjusts member countries' production targets based on current and expectations of

future supply and demand.

Supply: Non-OPEC

Non-OPEC countries around for 60% of total world oil production. North America, regions

of the former Soviet Union, and the North Sea are some important oil producers among them.

Figure 15: Non-OPEC liquid fuels production vs WTI crude oil prices


In contrast to OPEC which follows cartelisation, non-OPEC countries make independent

decisions about oil production. In OPEC, oil production is mostly in the hands of national oil

companies (NOCs) while in non-OPEC countries, international or investor-owned oil

companies (IOCs) perform most of the production activities. Primary objective of NOCs is to

providing employment, infrastructure, or revenue that impact their country. In contrast, IOCs

seek to increase shareholder value. As a result, non-OPEC investment and future supply

capability are affected by changes in market conditions.

Producers in non-OPEC countries are generally regarded as price takers, that is, they respond

to market prices rather than attempt to influence prices by managing production. As a result,

non-OPEC producers tend to produce at or near full capacity and so have little spare capacity.

Lower levels of non-OPEC supply tend to put upward pressure on prices by decreasing total

global supply and increasing the dependence on OPEC.

53 | P a g e

Figure 16: Projected non-OPEC liquid fuels production


Non-OPEC production generally occurs in frontier areas such as the deepwater offshore and

through unconventional sources such as oil sands. This involves high finding and production

costs compared to OPEC countries and thus a cost disadvantage.

In addition to non-OPEC crude oil production, natural gas production provides additional

supplies of liquids, called natural gas liquids (NGLs). Rising natural gas production in recent

years has resulted in substantial increases in NGLs.

Oil prices are affected by both actual production and expectations about future supply from

non-OPEC countries. From 2005 through 2008, final production reports for non-OPEC

production were consistently lower than forecast expectations. This reduction in anticipated

production was not accounted for by the world, thus being forced to rely more heavily on

OPEC crude, drawing down the levels of spare capacity. The downward revisions in

expectations of non-OPEC production contributed to upward pressure on oil prices.

Balance

Inventories serve as the balancing effect between demand and supply. During periods 2008,

2009 when due to economic downturn there was unexpected drop in world demand and

production exceeded consumption, crude oil and petroleum products were stored for expected

future use. In contrast, when consumption outstrips current production, supplies can draw on

54 | P a g e

the inventories accumulated to satisfy customer demands. Due to the uncertainty of supply

and demand, petroleum inventories serve as a precautionary measure.

Refineries and storage terminals can store crude oil and/or finished products like heating oil,

and diesel to prepare for seasonal fluctuations, refinery maintenance, or unexpected weather.

Petroleum products such as heating oil and gasoline display seasonal variations in demand;

inventories rise when consumption is lower and come down when consumption increases.

Thus, inventory levels on y-o-y basis serve as a better parameter to assess the inventory.

Inventories level also depends upon current oil price and future price expectations. If market

expectations indicate a change toward higher future demand or lower future supply, prices for

futures contracts will increase, encouraging inventory builds to satisfy the otherwise

tightening future balance. Conversely, if market participants notice an increase in crude oil

storage, this increase can indicate that current production surpasses current consumption at

the prevailing price. Spot prices will likely drop to rebalance demand and supply.

This balancing between current and future prices and between supply and demand through

inventories is one of the main connections between financial market participants and

commercial companies with a physical interest in oil, both of whom engage in futures trading.

Figure 17: OECD liquid fuels inventories vs WTI futures spread


55 | P a g e

References

India Infrastructure

Oil and Gas Asia

Petroleum Planning and Analysis Cell

The Economic Times

Reserve Bank of India

BPCL Annual Report, 2011-12

WWW.MONEYCONTROL.COM

WWW.NATURALGAS.ORG

WWW.PETROLEUM.NIC.IN

http://www.moneycontrol.com/

http://www.naturalgas.org/

http://www.petroleum.nic.in/

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