UNIVERSITY OF PETROLEUM & ENERGY STUDIES

CENTRE FOR CONTINUING EDUCATION

EXECUTIVE MBA

(OIL & GAS MANAGEMENT)

SEMESTER III

YEAR: 2014 SESSION: JULY

ASSIGNMENT – 1

FOR

Understanding Natural Gas Business

(MBSO 803D)

(TO BE FILLED BY THE STUDENT)

NAME: _BINODH D____________

SAP NO/REGN. NO: _500028040_____________

Section A (20 Marks)

Write short notes on any four of the following

1. World Natural Gas Consumption

World Natural Gas Consumption

In 2009, among all fuels, natural gas was the only fuel which saw a rapid decline in consumption by 2.1% globally. This has been the largest decline till date. Excluding Middle East and Asia Pacific, consumption declined in all areas. Russia broke all the records by showing a decline of 6.1% in consumption. Even the OECD consumption fell by 3.1%, the highest since 1982. However, the decline suffered by the US. was comparatively modest at 1.5%, the reason being the feeble prices which enhanced the competitive status of the gas against other fuels. Iran showed the highest growth in terms of volumetric consumption. Even India showed a considerable growth of 25.9% which was the highest in terms of percentage. lists the top ten countries in terms of consumption of natural gas in 2009.

Natural Gas Consumption of the World 2009

Rank (Total ) Country Natural Gas Consumption(thousand cubic meters)

Per capita (cubic meter)

1 United states of America

646,600,000 2105

2 Russia 367,500,500 26243 Iran 119,000,000 18064 Germany 96,260,000 11695 Japan 94,620,000 7456 Canada 94,620,000 28267 Great Britain &

Norhen Ireland87,450,000 1431

8 China 87,080,000 659 Italy 78,120,000 134410 Saudi Arabia 77,100,000 2688

Some of the significant energy agencies" of the world have projected that there would be considerable increase in the demand of natural gas in the coming 20 years with the developing countries projecting the largest increments.

3. Natural Gas Marketers

Natural Gas Marketers: Any party who engages in the sale of natural gas can be termed a marketer, however they are usually specialized business entities dedicated solely to transacting in the physical and financial energy markets. It is commonplace for natural gas marketers to be active in a number of energy markets, taking advantage of their knowledge of these markets to diversify their business. Many natural gas marketers are also involved in the marketing of electricity, and in certain instances crude oil.

Marketers can be producers of natural gas, pipeline marketing affiliates, distribution utility marketing affiliates, independent marketers, and large volume users of natural gas. Marketing companies, whether affiliated with another member of the natural gas industry or not, can vary in size and the scope of their Operations. Some marketing companies may offer a full range of services, marketing numerous forms of energy and financial products, while others may be more limited in their scope. For instance, most marketing firms affiliated with producers do not sell natural gas from third parties; they are more concerned with selling their own production, and hedging to protect their profit in margin from these sales.

There are basically five different classifications of marketing major nationally integrated marketers, producer small geographically focused marketers, aggregators, and brokers.

The major nationally integrated marketers are the ‘big players’, offering a full range of services, and marketing numerous different products. They operate on a nationwide basis, and have large_ amounts of capital to support their trading and marketing operations. Producer marketers are those entities generally concerned with selling their own natural gas production, or the production of their affiliated natural gas production company, Smaller marketers target particular geographic areas, and specific natural gas markets. Many marketing entities affiliated with LDCs are of this type, focusing on marketing gas for the geographic area in which their affiliated distributor operates. Aggregators generally gather small volumes from various sources, combine them, and sell the larger Volumes for more favorable prices and terms than would be possible selling the small volumes separately. Brokers are a unique class of marketers in that they never actually take ownership of any natural gas themselves. They simply act as facilitators, bringing buyers and sellers of natural gas together.

All marketing companies must have, in addition to the core trading group, significant ‘backroom’ operations. These support staff are responsible for coordinating everything related to the sale and purchase of physical and financial natural gas; including arranging transportation and storage, posting completed transactions, billing; accounting, and any other activity that is required to complete the: purchases and sales arranged by the traders. Since marketers generally work with very slim profit margins, the efficiency and effectiveness of these backroom operations can make a large impact on the profitability of the entire marketing operation.

In addition to the traders and backroom staff, marketing- companies typically have extensive risk management operations; the risk management team is responsible for ensuring that the traders do not expose the marketing company to excessive risk.

Top-level management is responsible for setting guidelines an. risk limitations for the marketing operations, and it is up to the risk management team to ensure that traders comply with the directives. Risk management operations are quite complex, and rely on complex statistical, mathematical, and financial theory ensure that risk exposure is kept under control. Most large losses associated with marketing operations occur when risk management policies are ignored or are not enforced within the company itself.

The marketing of natural gas is an integral part of the natural gas Supply chain. Natural gas marketers ensure that a viable market for natural gas exists at all times. Efficient and effective physical and financial markets are the only way to ensure that a fair and equitable commodity price, reflective of the supply and demand for that commodity, is maintained.

Natural gas is used in a number of markets. Industrial uses of natural gas represented the largest market with fuel and raw material applications. Natural gas is used to dry potato chips and automobile paint finishes. Natural gas is converted into fertilizer, methanol, and gasoline blending compounds. Natural gas is used in the residential and commercial sector for home heating and cooking. Natural gas used to produce electricity is growing rapidly.

Natural gas is moved to market through a network of gathering systems and pipelines. Natural gas from producing wells is collected in a field gathering system. The gas is processed in a natural gas processing plant where the heavier hydrocarbon liquids are removed and the gas is compressed.

The natural gas is sent to interstate transmission pipelines that transport the gas to consumers. Gas compressors along the line maintain the system pressure and keeps the gas flowing.

Natural gas marketing has changed considerably over the past decade. In the past, the natural gas transmission companies purchased the gas from producers, transported the gas, and sold it to local distribution companies or large users. The Local Distribution Companies (LDCs) sold the gas to end-users in residential, commercial, industrial, and utility power markets. The new deregulated natural gas market allows producers to sell directly to end-users.

Today's market has also fostered the development of natural gas marketers who can either collect suppliers and find markets for the production (supply aggregators) or collect customers and find supplies to meet their demand (market aggregators).

4. Worldwide Trends in LNG Trade

Gas Marketing Path

Title and Custody Related Title and Custody NOT Necessarily Related

LNG trade across the world has been growing substantially for the following reasons:Geographical

Emergence of new supply sources and markets Short Haulage Regionalization of markets.

Technological Advancements Reduction in exploration and development costs of gas. Reduction in liquefaction costs (scale up of train to 4 MMTPA) Shipping Optimization (Boil-off, bigger size potential) Floating LNG Production facilities

Commercial and Contractual Framework Emergence of bigger spot markets Supply Strategies - mix of contracted and spot supplies Swapping Cargo re-sales Softening of 'take-or-pay' provisions Innovative pricing and indexing Shorter duration of contracts Project start-ups with partial market tie-up Declining necessity of Government support.

Short-term Trading: Although long-term contracts have traditionally underpinned LNG market, there has been a low level of short-term or spot LNG trading throughout its history. Short-term trading began as sellers sought to utilise spare liquefaction capacity and some buyers found that gas demand increased more quickly than forecast. In the earlier times almost all short-term trading was between suppliers and buyers that already had a long-term contractual relationship

Afterwards this changed somewhat as shut-downs of Algerian production forced European buyers to seek LNG cargoes from Middle East and Australia. Further the US market also began buy spot LNG cargoes as Asia-Pacific sellers aimed to offload excess LNG following the downturn in demand in Japan, Korea and Taiwan.

Short-term LNG trades may follow a variety of pricing structures including indexation to crude oil or oil product prices, or netback from pipeline gas prices. In the Atlantic basin the proximity between the US and European markets provides sellers and buyers with an opportunity to arbitrage prices and divert LNG cargoes attract the highest price. Analysis of deliveries from the Atlantic LNG plant in Trinidad shows that when prices in the US are above European prices deliveries will be diverted to the US from Spain whereas the situation reverses when European prices are above US prices.

The main factors needed for the expansion of short-term trading are surplus LNG supply, market demand and receiving capacity, uncommitted ships, and flexible contracts. At the current time the main constraints on the further development of short-term trading are the shortage of uncommitted ships and the lack of flexibility in existing contracts. This seems likely to change in the near future as a number of uncommitted ships come online and buyers push for greater flexibility in supply contracts. Given these factors, the short-term LNG market is expected to expand somewhat in the medium-term, however, the large investments and commitments required for the construction of LNG plants, ships and terminals, is likely to prevent the short-term market replacing the current framework of long-term contracts.

Outlook for LNG

LNG trade has grown significantly in recent years by almost doubling by 2010 and is expected to get tripled by 2015. Although if these forecasts may be over optimistic, further acceleration in the pace of change will be needed. Expected gas supply gaps in the USA and Europe, and reducing If LNG costs, make LNG an increasingly attractive prospect for these growing markets. The opportunities for sellers to arbitrage prices between the US and European markets also increase the attractiveness of trading in the Atlantic basin. The Atlantic basin LNG demand grew by an average of 12%/year. Growth in the Asia- Pacific region has been slower, at 5%/year over the same period, and prospects for growth in the existing markets are uncertain, however, India and China hold out the possibility of large new markets for LNG.

There are currently a very large number of liquefaction capacity expansions or Greenfield projects proposed, both in existing regions and new areas such as Russia, Norway, Iran, Venezuela, and End South-west Africa. This is likely to lead to fierce competition if between projects with only those able to secure markets proceeding to completion. The key issue for new projects will be cost, with the projects in the Atlantic basin having a significant advantage their proximity to growing markets.

The emergence of a buyers ‘market and increased short-term trading is changing the structure of the LNG market, including increased flexibility in contracts, and increasing volumes uncommitted liquefaction and transportation capacity. Sellers are learning to deal with new types of buyers, as new players such as IPPs and new entrant suppliers seek to secure gas supplies liberalizing gas markets. The development of short-term LNG trading will continue, however, the market is likely to remain largely dependent on long-term contracts in the medium long-term. The future is likely to owe much to three emergent trends.

Changes in downstream markets and the emergence of new markets that are forcing buyers to seek much more flexibility supplies than in the past.

Reductions in the costs of LNG to the point where it is already competitive with pipeline gas in a number of growing markets.

The development of short-term LNG trading and the flexibility this gives for LNG players to improve returns on investment and exploit and further develop niche market opportunities.

5. Tariff and Contract Price Structure

Tariff and Contract Price Structure

Economic theory of natural gas pricing implies that each unit; natural gas should be priced according to the incremental demand for supplying the next tranche, meaning that the price should set to recover the marginal cost per unit of exploration, production transportation and distribution as depicted below:

Two-part Tariff Structure:A two-part tariff structure in pricing of natural gas is an accept norm in gas pricing and has fixed and variable components.

Fixed component includes depreciation, interest and return equity and usually do not vary with the Volume of supplies a is also referred to as "Capacity" or "Demand" charge.

Variable components fluctuate according to the volumes of g supply and primarily include the purchase cost of natural g, and are referred to as "Energy" or "Commodity" charge. A pipeline tariffs, the variable component is generally the compression cost, which varies with the volumes of transported.

Some tariffs include a "Minimum Bill" clause, which provides for a set charge (relevant demand and/ or commodity charge) over period of time, which serves to limit the under-recovery of capital or fixed costs.

In lump-sum contractual situations, up-front payment is made: secure dedication of gas supply. Pricing clause permits the buyer fix the primary component of fuel cost in order to facilitate project financing.

The fixed unit price can be with or without periodic review and most often used with short-term gas contracts. Variable Price Situation may imply that all or part of the price determined by a formula using quantity data relevant to the circumstances according to the following variables:

comparable gas sales in the same or similar market in same time sales of alternative or competing energy sources a prices of "system gas" delivered in market

9 seasonally adjusted prices to account for demand average reference prices from other markets incremental or incentive prices for increase in load factor stepped-up price increase over time (e.g., escalation with reference to inflation) Indexed prices relating to changes in CPI or annual GNP deflator.

Most common pricing formula make reference to the price of alternative energy (gas, fuel oil, LPG being sold in the buyer's market) and employ market "equalizers" such as:

date when the contract was entered into other material circumstances (shortage, surplus) load factor seasonal conditions allocation between demand and commodity components "weighting" according to alternative fuel's respective share of market.

Very often pricing formula becomes Weak due to lack of access to Price reference material (Platt's, Reuters, Asia Pacific Petroleum, etc.) leading to disputes over method of calculation, subjectivity “ uneconomic", "marketable price"), potential regulatory Intervention, ineffective negotiation or arbitration procedures.

Quite often, price is arrived based on competitive bidding or as a result of a negotiated settlement. In such situations, principle of an a1"m’s length transaction" should be applied, which is very important considering that the "Government take" in terms of profit Petroleum and royalty may get adversely affected. Some of e recent pricing arrangements in the country have led to allegations of absence of transfer pricing leading to potential loss revenue to the exchequer due to lower selling price. Reader ma like to refer to related material available in the website MoP&NG - Report of the Gas Valuation Committee (www.petroleum.nic.in). While one may agree that the report do not attempt to define the principles of gas pricing; yet recommendations may have far-reaching consequences in terms a signal to the gas market that the Government, in order to protect its take; may reopen the price clause in situations where the price of natural gas has or could not be determined competitively. This implies an additional responsibility on both seller and buyer of gas to follow a transparent process in gas pricing. internationally vertically integrated entities in the gas value chain have quite often resorted to a non-transparent pricing mechanism resulting regulatory interventions.

Contract Price Structure of Natural Gas

In this sub-section, we will discuss the contract since structure natural gas.1. Pricing to Market Value: Gas pricing according to clos alternative fuel and is most commonly

used in the EU and LNG contracts in Asia.2. Pricing to Cost: Gas is priced to reflect cost of production transmission, storage, distribution

and rate of return investment. This is a classical seller's approach.3. Netback Pricing: This being a method for determining price of gas by deducting costs

incurred and profit margin from the selling price to the buyer; commonly used in spot sales contracts. This is a market-sensitive pricing commonly used spot sales contracts. This is a market-sensitive pricing approach where the producer becomes a "price-taker".

International Energy Agency's (IEA) Rule for Netback Calculation specifies that the buying price of gas (insurance and freight included) should not exceed 75% international price of crude oil. The buying price FOB S110 II not exceed 50 to 60% of the price of crude oil depending upon transportation (pipeline or LNG).

4. Two-part Tariff Approach: System supply contracts (like in case of power) for meeting base loads employ the two-P tariff approach with a Reservation Fee payable on maximum quantity available, regardless of volumes nominated or taken, plus a commodity charge for each thermal unit nominated and taken. The commodity charge tracks the spot or reference price and the reservation fee is a percentage of the commodity charge. If third party provides transportation, full delivered cost may not track alternative fuel price.

5. Other‘ Options: In the absence of regulatory environment, which regulates prices, to adjust competing objectives of adequate rates of return on private investment and reasonable consumer prices, international experience has shown that alternate fuel reference, alternate fuel price base and rolled in-prices or WACOG should be observed in setting natural gas prices through negotiation.

Section B (30 marks)

(Attempt any three)

2. Explain the factors driving demand for natural gas.

Global demand for natural gas is expected to expand significantly as more nations adopt environmentally cleaner fuels to meet future economic growth and prioritize alternatives to minimize the impact of increasing oil - based energy costs. The environmental benefits of natural gas are clear. Natural gas emits 43% fewer carbon emissions than coal, and 30% fewer emissions than oil, for each unit of energy delivered. Many of the most rapidly growing gas markets are in emerging economies in Asia, particularly India and China, the Middle East and South America, economies which battle the balance between air quality and living standards on a daily basis.

Factors Driving Demand for Natural Gas

The demand for natural gas depends on a wide variety of factors like economic activity, the competitiveness of gas versus other energy sources, environmental considerations, technology changes, the ease of access to supply and government policies. Any gas demand projections depend gravely on the assumptions made about these drivers, giving rise to uncertainties.

Economic Activity :

Being one of the most important drivers of natural gas demand, the relationship between the two is quite strong. Rapid economic growth increases gas consumption while economic slump contracts the demand. Economic growth can stimulate demand both in case of mature markets with well-developed infrastructure as well as less developed markets which are investing in infrastructure. It stimulates demand through:

Increased household incomes as well as higher commercial activity which fuel the requirements of space and water heating in buildings;

Increase in industrial production which increases not only the demand for gas-fuelled process heat and power but also petrochemical feedstock demand; and

Increase in demand for electricity which increases the gas demand for power generation.

One of the largest gas-using sectors today is power generation which is projected to become the biggest driver of natural gas demand in the coming years. In terms of power generation, gas demand is very susceptible to changes in the GDP rates. When an average global study was conducted from 1990 to 2008, it was found that 1% increase in the GDP led to 1% increase in the gas use in power sector. This shows that the elasticity of demand to GDP growth was 1. However during the same period, it was found that the elasticity of gas demand for both buildings and industry was at 0.6 and 0.4 respectively. These relationships have remained the same over time except in 2010 where there was an unusual blip.

As there is considerable uncertainty in the future economic growth, the similar levels of uncertainty arise in future gas demand. In advanced countries, the recovery in the recent global economy has been very‘ fragile and thereby there is uncertainty in the short term prospects. Though the economic growth outlook in non-OECD countries seems to be brighter, however any long or short term I minor changes in the GDP may have a great effect on the gas demand.

Competitiveness versus Other Energy Sources

Natural gas has strong competitors in the form of alternative fuels- Coal, nuclear, oil and oil products and renewable-based technology give stiff competition to the gas when it comes to power generation i In most of the countries, demand for nuclear and renewable is highly affected by the policy of the government. This limits the importance of market factors in gas competition. The demand for oil based power is very small and decreasing in OECD, but it is still used in some non-OECD countries. Coal, heavy fuel oil and electricity are the main alternatives to gas in industry while in the residential and commercial sectors, gas faces competition with liquefied petroleum gas, heating oil and electricity. In most uses it is difficult to switch between gas and other fuels due to sunk costs of physical equipment.

However, the power sector is an exception as depending upon the prices, relative fuels etc.; it possesses the operational capacity to switch between the various fuels. The evaluation of gas economics with other options by Various energy consumers especially power generators is conducted by comparing relative fuel prices, operational factors, equipment costs, policy and regulatory risks which have chances of being effected by social responsibility with relation to environmental or safety issues and other market risks. Decisions with regard to investment depend upon the future gas prices expectations while the operational decisions depend upon short term price of gas in comparison to the competing fuels. Gas prices differ considerably depending upon regions, nearness to the supply sources, subsidy and tax policies and price mechanisms. Regulations with regards to greenhouse gas and emissions may also effect the inter-fuel competition especially if high price is fixed for CO2 emissions. In countries where in this CO2 mechanism has been introduced, natural gas enjoys an upper hand over carbon intensive coal, but such countries give more preference to renewable and nuclear as they are lower carbon sources. However, factors like lower capital costs and shorter lead times for construction are in favour of natural gas.

Environmental Impacts of Energy Use

Fuel and technology selection is increasingly becoming dependent On policies related to local pollution and climate change. Natural gas has a favourable environment profile as compared to coal and Oil Combustion, so it is fast becoming the most sought after fossil fuel in both power generation and end use sectors. This trend is expected to grow particularly in developing countries which have dire need of energy as their growing economy has added pressure on Water, air and soil quality. Moreover in comparison to other the renewable-based generation, the gas fired generation is gaining popularity as it is capable to limit climate change. In comparison to coal and oil, gas decreases or

avoids most of the environmental damage caused by use of fossil fuels. The pollutants emitted by gas is fewer in number as compared to other fuels. and these pollutants include nitrogen oxide (NOX) which leads to ground level ozone formation and acidification, sulphur dioxide (So2) along, with NOX which causes acid rain as well as the particulate manner along with NO); which leads to smog and poor air quality.

As a result, for cleaner air in and around cities, it is desirable to use gas in power generation, household and industrial boilers and vehicles. Moreover the visual intrusion on the landscape of transport and storage of gas is considerably smaller than coal as it is moved mostly by pipelines and stored underground. On the other hand, coal requires extensive rail and road networks. Gas usage also does not produce any end products like coal ash or used up nuclear fuel which is difficult to manage. After combustion, natural gas emits less CO2 than its counterparts. It emits approximately 40% less CO2 than coal and 20% less than oil. As far as power sector is concerned, the gas produces half of the 40% of global energy related CO2 emissions due to the modern combined-cycle gas turbines. These figures are calculated for per unit electricity. The only mandatory CO2 emissions which are operational are located in New Zealand and the European Union. In these countries, the price of CO2 emissions are directly considered in the operations and investment decisions. In countries I where the cost of CO2 emission is not so obligatory, power companies and industries are busy speculating the government’s future plans in tackling climate change.

Changes in Technology

Technology developments across energy types and in end use equipment as well as appliances strongly affect the fuel choice and the efficiency of gas consumption. As compared to past technical initiatives which were driven by the need to lower costs as well increase efficiency, the present focus is more on reducing CO2 emissions.

Future fuel choice is largely dependent on the technological advancements in the power generation sector. The increasing thermal efficiency of CCGTS till 59% as compared to 47% in Ultra supercritical coal-fired plants, has given a distinctive advantage to natural gas over coal. In future, it is predicted that two major technological advances will considerably affect the demand of it natural gas. Firstly, carbon capture and storage which will increase its competitiveness. Secondly, sufficiently cost effective battery which can operate plug-in hybrid as well as fully electrical vehicles and would cause a shift from the fuel operated to electricity operated vehicles.

In other sectors inventions leading to efficient gas consuming equipment’s would either lower the gas consumption or reduce its rate of growth. In non-OECD countries, there is considerable scope of lowering the gas intensity in manufacturing sector by adopting commercially available technologies. As far as residential and commercial sectors are concerned, introduction of government standards and incentives can encourage people to adopt the more efficient technologies like condensing boilers at a faster rate. Likewise, strict building codes as well as better enforcement can help in lowering energy or gas use or substituting gas with electricity.

Access to Supply

The consumption of gas can be easy if the production and transport infrastructure is developed in such a way to make supplies available. Large, capital intensive infrastructure is required along the supply chain for new gas markets. These may include investment in production and processing facilities, LNG liquefaction and regasification terminals, long distance high pressure transmission pipelines, storage facilities and local distribution networks. This can only occur if investors are confident enough about the sufficient future gas demand and even after covering the risk factor, the expected returns justify the upfront costs. In developed markets, where gas infrastructure is well

established, the unit cost of incremental supply capacity is usually lower. Gas transportation through pipeline or liquefied natural gas is comparatively more expensive than that of oil. This is due to the fact that capital intensive equipment is required to overcome the lower energy density of gas. Additionally reconciliation of political and economic interests is needed in case of long distance gas pipelines which cross several countries. As a result, the nearness to the resources has been a prime factor in the development of regional gas markets. Recently due to the massive expansion of global LNG supply capacity, the new or existing markets have been awarded to grab the opportunity of securing LNG supplies even if located at a distant place. The construction of distribution networks is required for the natural‘ gas use in the commercial, transport and residential sectors. As building these networks is costlier, the delivered cost of gas per unit is relatively higher than the cost to large users who are directly supplied through the transmission network. However rising incomes of people particularly in the non-OECD countries mainly Asia and Latin America have made it possible to handle these increased costs.

Government Policies

Gas consumption and fuel choices are affected by the government policies and instrument types used for implementation. The affect may be direct, indirect or sometimes unintentional. For instance, greater gas use may be encouraged by energy and environmental policies which offer favourable taxation or subsidies to end use prices. On the other hand, demand can be constrained by mandating or promoting alternative technologies like nuclear power and renewable sources.

Many countries are facing high uncertainty in terms of future energy policies. One of the biggest uncertainties is the strength and nature of action which will be taken to handle climate change. This may be in the form of financial incentives, production targets and capacity mandates to support the deployment of low-carbon power generation technologies. Removal of fossil fuel subsidies and pricing reforms which may be stimulated by environmental or economic reforms will also be vital. The share of gas in the energy mix may also be affected by the regulations to reduce local pollution. This particular step may be taken by least developing countries which are coping with environmental imbalance due to the intensive use of energy. All in all, natural gas will benefit more from stringent environmental policies aimed at reducing pollution levels evolution and growth.

3. Discuss the gas pipelines policy and regulatory framework in the Indian oil & Gas Sector.

Gas sector and gas transport in particular is developing rapidly in India. With successful results from exploration efforts under NELP rounds and huge finds in KG basin coupled with encouraging results from western coast as well as upcoming LNG terminals at Dahej and Hazira (also Dabhol), there is an urgent need to develop transmission lines connecting different states. Whereas, local distribution system may get developed over a period of time with growth of demand, transmission system needs to be taken up on top priority to enable various gas producers and LNG importers to reach market. With an aim to mote investment in gas pipelines and to provide inter-connectivity between regions, consumers and producers, Government proposed certain guidelines for laying natural gas pipelines for the interim period till the Petroleum Regulatory Board Bill is passed by the Parliament and is notified for enforcement.

Gas Pipeline Policy

The McKinsey & Co. had submitted draft recommendations in a report titled ‘Developing a Pipeline Regulatory Regime for India’. Based On these recommendations, the Ministry of Petroleum Natural Gas had issued a notification laying down guidelines for laying petroleum product pipelines. These guidelines do not cover the laying of natural gas pipelines; based on various reports such as ‘Regulatory Framework for the gas industry in India’ by i ational Economic Research Associates

(NERA), the report of McKinsey & Co., etc. and discussions with GAIL and other industry players, a draft pipeline policy has been formulated for consideration.

It has been proposed that there will be three categories of natural gas pipelines as follows:

Low pressure pipelines: All pipelines developed for the transportation of low-pressure gas produced from isolated and marginal gas fields.

Local distribution pipelines: Pipeline developed for the transportation and local distribution of natural gas through an integrated pipeline network to domestic, CNG, commercial and small industrial consumers.

Transmission pipelines: All medium to high-pressure transmission mains, other than low pressure pipelines and local distribution pipelines, laid for transporting gas from the landfall point/delivery point to any location within India.

For the first two categories above, any entity will have the freedom to lay pipelines subject to statutory approvals. However, for Transmission pipelines categorized at (3) above which will be high pressure bigger diameter long distance pipelines, the Government will have the power to nominate any company for laying such, pipelines. Further, all new pipelines will be on non-discriminatory open access basis for booking of pipeline capacity as well as for any available excess capacity.

The transportation tariff for the pipelines commissioned after the date of publication of the‘ notification in the official gazette will be subject to the control orders or the regulations that may be issued by the Government or the statutory authority in this behalf under any law for the time being in force. Gas transmission will be provided on the basis of unbundled services, i.e. separate provision for transportation and gas supply services.

All gas pipelines will be built on common carrier principle and their capacity will be expanded or an additional pipeline lay if so desired by the regulator to meet the requirement of new players. If the person owning the pipeline is unable to expand it or take Steps within a reasonable period to do so, the regulator may get expansion done through the National Nodal Authority or in other manner. The pipelines will be used by all players on non-discriminatory basis. Tariff for the transmission pipeline‘and/or for the distribution pipelines would be approved by the regulator so as to provide a reasonable rate of return as may be fixed by the regulator. This tariff should be applied as a cap to enable lower negotiated rates based on market prices. The draft policy is under consideration and final policy is yet to be announced.

Since, pipelines create natural monopolies, a comprehensive regulatory framework is required. The role of the regulatory authority would include ensuring adherence to stipulated safety and quality norms, ensuring that facilities are not needlessly duplicated, and determining the tariff that is attractive to investors and yet does not exploit consumers.

Regulatory Framework

Historically, the Government has regulated prices and investments in the Indian oil and gas sector. However, in the past few years, the Government has moved towards a market driven economy by withdrawing the restrictions imposed on investments and by decontrolling the prices falling under the Administrative Price Mechanism. Additionally, the Government also mooted a proposal for a common regulatory body for the natural gas and petroleum sector.

The Indian gas market is presently in a transition from an administered control regime to a market driven system. Under the new policy framework in the upstream side, the New Exploration and Licencing Policy (NELP) and the Coal Bed Methane (CBM) policy are under operation, and companies are free to market the gas Produced from the indigenous blocks (acquired by bidding proceses) directly in the domestic market at market determined prices. The import of gas through

LNG and cross-border pipeline gas imports are under Open General Licence (OGL), and companies are free to market the imported gas at market determined prices. However, the gas produced by the National E&P companies (ONGC, OIL) from the blocks acquired by them on nomination basis is under administered pricing mechanism. Shortly, the domestic gas prices are also expected to progressively move towards a market based pricing system. It is certain that the gas market in India is under restructuring, and in the near future, there would be multiple companies involved in gas marketing related activities. Over the medium/long term period new cross country gas pipelines will be required to meet the growing gas demand in existing and new emerging markets in the country. In view of the above changes taking place in the Indian gas sector, an appropriate regulatory mechanism would need to be established to: ensure systematic development of the Indian gas market in a cost effective, safe and competitive manner. Keeping in view the increasing size of the natural gas market in India, it is important; to attend to some of the key policy and regulatory aspects of the; Indian gas industry.

The R-Group Committee was set up by the Government in the mid-nineties in order to make recommendations on the future structure of the petroleum industry. According to the Group, regulatory framework is necessary to ensure that all gas marketers have access to the pipelines grid and that the pipelines are operated in accordance with the prescribed technical and safety standards. The role of the Gas Regulatory Authority would depend on the structure and the stage of development of the gas market.

The R-Group report succeeded by the HV-2025 report prescribes the policy framework for the hydrocarbon sector in India. As regards the policy itself, the Government of India came out with bold initiatives in the upstream sector in the form of NELP and CBM policies. Hydrocarbon Vision-2025 was a high level exercise on the policy framework initiated by the Prime Minister, and carried out by a group chaired by the Finance Minister. The report provided continuity in policy directions to many of recommendations of the R-Group Committee. It laid down recommendations targeted at achieving self-reliance in the India. hydrocarbon sector through increased indigenous production an investments and the promotion of competition amongst the players by creating a level playing field.

To boost the level of exploration activity in the country so that new finds can be made and the levels of crude oil and gas production increased in the years to come, a need was felt to attract both National Oil Companies (NOCs), as well as private sector oil Companies to invest in this critical area of E&P. Therefore, a New Exploration Licensing Policy (NELP) was formulated by the government to provide a level playing field in which all parties could compete on equal terms for the award of exploration acreage.

Gas Allocations

The regime of allocation was based on the premise that gas was in short supply and that economic prioritization was necessary to use the gas. Following the recommendations of the Varadharajan Committee, these allocations were based on the imputed economic value of gas use in the various sectors, subject to preference for the power and the fertilizer sectors. The Government of India established the Gas Linkage Committee (GLC) in order to reassess the potential of gas production and establish the priority of gas supply to projects given the limited availability of gas. Based on the recommendation of the GLC, the Ministry of Petroleum and Natural Gas makes three types of gas allocations:

Firm allocation is made to a consumer when gas availability has been assured by producers and the consumer has established the viability of the project and is in a position to enter into a gas purchase agreement within 60 days. In this case, the gas supply contract would typically be subject to a take-or-pay arrangement for up to 80 per cent of the contracted quantity.

Fall-back allocation is made to a consumer when the availability of gas is dependent on the failure of the firm consumers to purchase the allocated quantity of gas. Fall-back allocations

are also made when the gas is supplied from g isolated and small gas fields, where the availability of gas has not been confirmed for a long periods and the supply is liable to disruption. There is no take-or-pay arrangement, and a Consumer pays only for the gas actually consumed. Fall-back Consumers would usually have dual-fuel capability and would use alternate fuels when gas is not available.

In Principle, allocation is made to consumers based on the projected availability of gas and is subject to the consumer establishing the viability of the project.

First departure from this system of allocation has been made in the case of Private developers of discovered fields under NELP. Additional gas availability from NELP areas and Pvt./JVCs sector Understanding Natural Gas Business is not the subject of allocation for GLC. Only gas from blocks nominated comes under the preview of GLC.

Today, gas producers from NELP/CBM blocks are free to choose their customers and sell gas at negotiated prices. Today, the natural gas market in India is in the midst of pi transformation. To promote private investment and more widespread use of natural gas in its economy, the Government has been evaluating alternatives to its existing regulatory framework A and organizational structure.

Petroleum and Natural Gas Regulatory Board (PNGRB)

With the increasing presence of private players and the move‘ towards increasing the extent of gas distribution in the country, the Petroleum and Natural Gas Regulatory Board was set up, under the PNGRB Act, 2006. The PNGRB regulates the refining; processing, storage, transportation, distribution, marketing, and sale of crude oil, petroleum products, and natural gas. It also protects the interests of consumers and entities engaged in specified activities in these areas and is responsible to ensure uninterrupted and adequate supply of crude oil, petroleum products, and natural gas to all parts of the country and to promote competitive markets. The PNGRB issued guideline; relating to city gas distribution network and natural gas pipelines in 2007-08 and 2008-09.

Integrated LNG Policy

In order to ensure energy security, the Government has been planning to stipulate certain norms for import of LNG into India Based on the pilot plan prepared by the Department of Shipping and Ministry of Surface Transport, the Government has set up Committee of Secretaries (CoS) from the five core ministries draft an integrated LNG Policy. The draft policy prepared by CoS was worked upon by the Ministry of Petroleum and Natural G39 which was forwarded to the Cabinet Committee of Economic Affairs (CCEA) for approval. The CCEA is to finalize the LNG Policy that lays out the minimum norms relating to domestic participation in LNG business, grants incentives to promote LNG and rationalizes duties for various segments.

Draft Policy for National Gas Pipelines: With an aim to moot investment in gas pipelines and to provide inter-connectivity between regions, consumers and producers, Government has proposed certain guidelines for laying natural gas f pipelines.

Modified Gas Pipeline Policy (July 28, 2004) : As per the directions, the MoP & NG is of the view that all future common carrier projects will go to companies which provide, among other parameters, the most competitive tariff. The criteria address the following objectives:

Provide a framework for future growth of the pipeline infrastructure. Promoting competition in gas sector. To promote investment from public as well as private sector.

To provide interconnectivity between regions, consumers and producers. To promote competition among entities avoid infructuous investment, maintain/increase gas

supplies and secure equitable distribution of natural gas throughout the country. Protect consumer interest.

4. List and explain the characteristics of Market Sectors of Gas.

Gas usage, in a free market, would compel competition in securing gas at most competitive terms possible - price, period and other contractual terms over the economic life of the project. In an Indian context, the sectoral expectations have remained unfulfilled due to extremely poor availability of gas and due to the lack of pipeline infrastructure.

In recent years, the LNG business has experienced an impressive increase in activities, mainly due to decreasing development costs, higher prices of gas and growing demand, which jointly contribute to the creation of more potential opportunities for old and new Supply sources.

CNG as an automobile fuel improves engine efficiency. The running cost of CNG is lower compared to diesel and gasoline. The maintenance cost is also low due to better fuel quality. The energy content per kg of CNG is very similar to that of petroleum based fuels, but it has lower energy content per unit of volume.

Characteristics of Market Sectors of Gas

A Gas market exists to serve its sectoral customers - Power, Fertilizer, Petrochemical, CGD networks and other small Industries (ceramic, glass, steel), which use gas either as fuel and/or feedstock. Environmental concerns, ease of convenience, economics, secured supply terms and dual fuel/feedstock options are generally the drivers for gas usage in these sectors. The primary difference in energy use of natural gas versus other fossil fuels is its lack of fungibility (exists in long-term commitment along the value chain and hence has a limited spot trade) and that it cannot be as economically stored and transported as other fossil fuels.

Perceptions on gas usage vary in terms of sectoral expectations –A power plant is interested in the calorific value of molecules of natural gas to be supplied; fertilizer unit is interested in gal composition, as it effects the production of carbon dioxide, which is required for urea production; a petrochemical plant looks a whether the gas is rich or lean and the levels of C2/C3 and higher olefin contents, as these guide the extent of fractionation possible; a CGD network perhaps could do with a lean gas as the primary requirement is that of space heating, cooking fuel and small industrial/commercial fuel applications.

The market place for the sectoral end uses - electricity, fertilizers; petrochemicals, other industrial products (glass, steel, ceramics etc.) guides the issue of affordability of gas price. In controlled markets like India, where fertilizer and electricity prices are either controlled or subsidized, the end users would be forced to seek concessional or subsidized gas price. However, since the petrochemical end products, like, ethylene, propylene, etc. compete globally; the affordability would be guided by the global trends ii; the differential between the "Crac versus Frac" spreads. Of course the extent of the impact of the fuel/feedstock price in the overall cost structure of a user's product would finally decide the affordability considerations.

A CGD customer, in colder climates where an appropriate fuel fo- space heating is the issue, would primarily look at the relative economics of the fuel (electricity, FO, gas) and the heating. Equipment cost before choosing for gas as a fuel.

Premium and Non-premium Markets

The concept of premium gas market segment refers to a situatio11 where it is possible to charge a differential price for different categories of customers or for even different customers within the same category. Such a situation follow an opportunity cost pricing approach - i.e., price is based on the customer's "ability to Pay.

When compared with the cost of alternative fuel option assuming there exists a dual fuel option (both in terms of linkage and an operational switch ability in terms of the equipment). Very often, the virtual monopoly position of the seller could construe some over pricing" for premium segments considering the criticality of the buyer's process in terms of "use or forego profits" position. A non-premium segment would generally be a small volume consumer (not necessarily on an aggregate basis as a category) with no switch ability option and could also be with reference to relatively high cost of network coverage in relation to the revenue.A certain cross-subsidization may be resorted to balance out the a cost and revenue requirement.

Natural gas pricing in the developed economies in the North America, Europe, Korea and Japan with significant space heating T’ requirements generally consider the residential customers as the premium segment with the highest prices (truly reflective of the cost of service); pricing for the electricity sector being the lowest;and the other industrial/commercial pricing falling in between.

The basis of segregation of the Indian gas market segments as premium and non-premium is entirely different, largely guided by the following factors:

Indian gas sector has remained undeveloped till date due to much lower adequate availability of natural gas to fully saturate the demand and resultant gas allocations, government price control on natural gas, extremely limited infrastructure and near-dominance of“ the nominated gas monopoly. The consuming segments therefore, could not be classified as premium or non-premium.

PNG segment in the domestic sector competes with a well-positioned LPG network, prices of which, is subsidized.The likelihood of continuance of subsidies for LPG domestic and the PDS Kerosene could mean the domestic PNG segment remaining a non-premium segment. However, newer premium residential construction with in a vertical design format could offer some scope for having a differential pricing.

PNG Segment in the non-domestic category (small industrial and Commercial) has much better paying capacity and a better Suitability option and therefore gas pricing could follow a linkage with the price of alternative fuels, such as, non domestic LPG, FO and LSHS. Here too, the currently prevalent mass diversion of subsidized LPG to non-intended categories, like hotels, small restaurants is a deterrent in following a differential pricing approach. Alternatively, such situation could be taken as a challenge by the proposed CGD entity with appropriate legislative backing in checking an i preventing such an abuse.

CNG segment could well turn out to be a premium segment, in the long-term considering the skewed pricing policy being followed in the pricing of alternative automotive fuels - MS & HSD. The downside could be the high cost of CNG infrastructure, cost of conversion and/or a lackadaisical approach by the city administration in pursuing a quicker phasing out of polluting vehicles and replacement by CNG vehicles. Further,oil companies shall continue to create market for premium quality fuels with lower levels pollution; yet this may come at a premium. An appropriate marketing strategy by the CGD entity with a focus advertising the possible long-term fuel economy, creating a awareness for a cleaner environment, tie-ups with OEM an automobile companies to bring down the cost of conversion seeking lower sales tax/VAT on CNG could help in making tlii a premium segment in the long-run.

A comparative position with regards to the affordability of price of natural gas by the anchor - load power sector indicate’ that this segment would remain a non-premium segment till the electricity reforms are fully implemented and the share of APM gas in the overall natural gas market decline significantly. The concept of premium segment could, however; be applied in

a slightly different context as well - the cost of connectivity for a power sector unit is the lowest (as compare. to a CGD network); and therefore a somewhat lower price realization, but a very large volume base could offer significant economies of scale. A gas producer and/or marketer would therefore be incentivized for an anchor load power customer, if order to justify laying the transmission pipeline and quickly monetize the gas discovery.

The affordability of the fertilizer sector for natural gas price is certainly better than the power sector, primarily due to the continuation of the retention pricing mechanism, where the- feedstock/fuel price is a pass through in urea price (due to the subsidy provision in the union budget) and the cost of alternative fuel, being Naphtha, which has always been higher ‘T than the market-determined price of natural gas.

The petrochemical sector using natural gas as feedstock for extraction of the C2, C3 and higher olefin contents is certainly a niche segment in the gas market. Over, the price of the finished product, not controlled, is subject to global competition, which in turn is governed by the economics of Frac spread" versus "Crack spread". The gas pricing strategy has to be dynamic and take into account the market in which the finished petrochemical product competes.

The other sectors for uses of natural gas, viz. in the refineries in the CPP and/or hydro cracker for hydrogen generation, steel producers, glass/kilns/ceramic industry, clearly are premium segments.

International Market Integration for Natural Gas

Over the last years, international trade in gas has significantly gained in importance. Traditionally, gas trade was limited regionally, due to a lack of pipeline infrastructure, and little availability of Liquefied Natural Gas (LNG) transport capacity. Growing intra-continental trade, e.g. within North America and Europe/Russia, and the development of LNG-tanker trade have led to an increasing integration of world gas markets. In the early years of this decade, there was even some arbitrage with LNG-tankers between the volatile markets of North America and Europe. Thus, one would expect to see increasing price convergence, now more than ever.

During the last decade, there was a certain split of prices between Europe and North America, due to regional segmentation of markets. However, there was an evidence of integration within the regional European/Japanese and North American markets, and the European/Japanese and the North American markets were connected to a much lesser extent.

Key Factors in Natural Gas Market Development

Some of the Key Factors in natural gas market development are mentioned below: Prices and flows reflect engineering constraints in a regulated Industry resulting in indirect

substitution of different plants towards/from base loads and over time, newer options appear in terms of fuel choice and fuel efficiency. Where fuel substitution does not take place, energy is replaced with labour and capital, leading to demand destruction/oversea outsourcing.

Liberalization causes prices and flows to reflect economic opportunities. Higher prices allow producers to drill for more expensive sources.

Section C (50 marks)

(Attempt all questions. Every question carries 10 marks)

Read the case “Legal Aspect of Oil and Gas Sector.” and answer the following questions:

Case Study: Legal Aspect of Oil and Gas Sector

Oil & Gas sector has a long history in India. First oil was struck at Makum near Margherita in Assam in 1867. First commercial oil discovery was made in Digboi in 1889. During the pre-independence period, the Assam Oil Company in the north-eastern and Attock Oil company in north-western part of the undivided India were the only oil companies producing oil in the country, with minimal exploration input. Consequently, while framing the Industrial Policy Statement of 1948, the development of petroleum industry in the country was considered to be of utmost necessity.

Oil and Natural Gas Commission was formulated in 1956. The liberalized economic policy, adopted by the Government of India in July 1991, sought to deregulate and de-license the core sectors (including petroleum sector) with partial disinvestments of government equity in Public Sector Undertakings and other measures. The Indian oil and gas sector is one of the six core industries in India and has very significant forward linkages with the entire economy.

More than 70% of the crude oil in India is imported. Oil imports during November, 2010 were valued at US $ 7725 million which was 2.31 per cent higher than oil imports valued at US $ 7550.4 million in the corresponding period last year.

OIL AND GAS INDUSTRY

Given India's targeted GDP growth, India's fuel needs are likely to expand at a substantial rate. India's per-capita consumption of energy and electricity is well below that of industrialized nations and the word average, meaning that there is scope for rapid expansion. At the same time, India already imports over 70 percent of its crude oil requirements, with its Oil imports during August, 2010 were valued at US $ 7795 million which was 12.4percent higher than oil imports valued at US $ 6936 million in the corresponding period last year.

Oil and Gas sector is divided into 3 parts

• Upstream

• Midstream

• Downstream

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 oil sector is also known as the exploration and production (E&P) sector. 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.

Exploration activity, prior to NELP, was dominated by public sector firms such as Oil and Natural Gas Corporation Ltd. (ONGC) and Oil India Ltd. (OIL). The sector received a major boost in 1974, when the massive Mumbai High fields were discovered off India's west coast.

In addition to the efforts to discover new fields, ONGC, in particular new technologies

Many other policies are introduced by Government of India for growth in indigenous crude oil and gas. Which are in progress and have led to many major discoveries.

Midstream

The midstream industry processes, stores, markets and transports commodities such as crude oil, natural gas, natural gas liquids (LNGs, mainly ethane, propane and butane) and sulphur. Generally midstream is clubbed with downstream industry.

Downstream

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 and Propane.

The total refinery crude throughput during 2009-10 at 160.03 million metric tonnes is 0.46% lower than 160.77 million metric tonnes crude processed in 2008-09 and the prorate capacity utilization in 2009-10 was 89.92% as compared to 107.43% in 2008-09.

India, which is already surplus in refining capacity, aims to emerge as a refining hub. Its favourable location, close to the oil-producing regions of the Middle East renders it an advantage in this quest and the ability of the latest refineries to process heavy, low-grade crude, will further help in this regard.

India today boasts of surplus refining capacity, with further large expansions planned. The major expansions are for the Vadinar refinery of Essar, the Indian Oil Corporation (IOC) refinery at Paradeep and the planned refineries at Bina in Madhya Pradesh by BPCL and Bhatinda in Punjab by HPCL-Mittal Energy.

The Government of India has been providing tax incentives and fiscal incentives to new refineries. The new RPL refinery, for example, benefited from its Special Economic Zone (SEZ) status. However, current tax holidays would not be available to non-public sector to refiners that commence activities after April 1, 2009.

POLICIES AND REGULATIONS

Over the years various policies have been implemented by the Government to regulate and develop the oil and gas sector. The Petroleum Act to control issues relating to import, transport, storage, production, refining and blending of petroleum was already in place since 1934. Further, the Oil Fields (Regulation and Development) Act, 1948 and the Petroleum and Natural Gas Rules, 1959 provided regulatory framework for domestic exploration and production of Oil & Gas.

1. Hydrocarbon Vision

The Hydrocarbons Vision 2025 lays down the framework which would guide the policies relating to the hydrocarbons sector for the next 25 years. Issues such as E&P, refining, marketing, external policy, oil security, tariff and pricing, and restructuring and disinvestment are addressed by the Group, to ensure that an optimal mix of energy resources are made available to the consumer at the right price. The Hydrocarbons Vision 2025, no doubt, spells out the government's strategy and operational style with regard to this vital industry.

2. Eleventh five year plan

Availability and access to energy are considered as catalysts for economic growth. The envisaged growth of the economy at 9% in the Eleventh Plan cannot be achieved without a commensurate increase in the availability of energy. The current level of production barely caters to 26% of the petroleum products demand and the balance oil requirements are met by importing the crude. The policy issues that need to be addressed in the petroleum and natural gas sector relate to oil and gas security, pricing of petroleum products, pricing of domestically produced natural gas and its allocation to the power and fertilizer industry, ensuring competition and open access in the pipeline transportation and distribution grid, and conservation of petroleum products and natural gas.

Following are some key points:

Oil and gas security

Development of alternate fuels

Petroleum Product Pricing

Infrastructure development

Physical Programme

Research & Development

Hence these are some of the reforms which 11th plan proposes to inculcate in the oil and gas industry.

3. NELP (New Exploration Licensing Policy)

Prior to the NELP, the Oil fields (Regulation and Development) Act, 1948 and Petroleum and Natural gas Rules, 1958 regulated the issue of license and PSU's. ONGC and OIL were the only public sector companies involved in exploration and production till 1997 while IOCL was the primary entity concerned with refining and processing oil after extraction. "The discoveries made under the NELP have resulted in in-place hydrocarbon reserve accretion of a staggering 642 million tonnes of oil and oil equivalent gas, a total of 87 oil and gas discoveries have been made in 26 blocks under NELP during this period.

The main features of the terms offered by the Government inter alia include - no signature, discovery or production bonus by the bidder; income tax holiday for seven years from the start of commercial production, no customs duty on imports required to be payable for petroleum operations, biddable cost recovery limit up to 100 per cent, royalty to be payable by the contractor on ad valorem basis, freedom to the contractor for marketing of oil and gas in the domestic market, fiscal stability provision in the contract and incentive for deepwater exploration with only half of the royalty payable in the initial seven years from the beginning of commercial production. Eight rounds of NELP have been completed till now and the Ninth Round has recently started in 2010. As on January 1, 2010, private and foreign investment in NELP blocks stood at around $14.8 billion.

Two major discoveries as production by Reliance Industries' (RIL) KG-D6 basin and crude oil production in Barmer (Rajasthan) by Cairn India are the result of NELP.

4. FDI in Oil and Gas Sector

The sector is fully open to foreign direct investment with 100 per cent equity through automatic route, subject to sectoral regulation that is equally applicable to domestic and foreign players. In Refining FDI up to 49% in case of Public Sector Undertakings, without involving any divestment or dilution of domestic equity in existing public sector undertakings FDI up to 100% in case of private companies.

Since Government of India's liberalisation policy, domestic as well as foreign companies have invested Rs.99714 Million during 2004-05 to 2009-10 in oil & gas sector.

5. Policy for Change in Price of Petroleum Products

In line with the recommendations of a High Level Expert Group headed by Dr. Kirit Parikh the Government is in the process of establishing a viable system of pricing of petroleum products. The Government has decided, consequent to a meeting of Empowered Group of Ministers held on 25th June, 2010 that the pricing of petrol and diesel, both at the refinery gate and the retail level, will be market-determined. However, it is proposed that increase in prices of diesel will be staggered over time to minimize the overall impact on the poor and the vulnerable. It has also been decided that in case of a high rise and volatility in international oil prices, Government will suitably intervene in the pricing of petrol and diesel. The Government is committed to provide available essential fuels, particularly cooking fuels to the common man at affordable prices. In view of the importance of the household fuels, namely PDS Kerosene and Domestic LPG, the Government has decided that the subsidies on these products will be continued. The PDS Kerosene and Domestic LPG Subsidy Scheme 2002 and the Freight Subsidy (for far-flung areas) scheme, 2002 have been extended till 31.03.2014. However, in order to reduce the burden of under recoveries, it has been decided to increase the retail price of PDS Kerosene by Rs.3/- per litre and of domestic LPG by Rs.35/- per cylinder at Delhi with corresponding increases in other parts of the country.

6. Policy for Development of Natural Gas Pipelines and City or Local Natural Gas Distribution Networks.

The natural gas sector is at the threshold of rapid growth in the country. With increased exploration efforts under NELP, large scale discoveries of gas in the East Coast, commissioning of the LNG import terminals in the West Coast, projected upcoming LNG terminals and the Government's initiatives in natural gas through transnational pipelines, there is an imminent need to provide a policy framework for the future growth of the pipeline infrastructure in the country with a view to facilitating the evolvement of a nation-wide gas grid and the growth of city or local gas distribution networks. The objective of the policy is to promote investment from public as well as private sector in natural gas pipelines and city or local natural gas distribution networks, to facilitate open access for all players to the pipeline network on a non-discriminatory basis, promote competition among entities thereby avoiding any abuse of the dominant position by any entity, and secure the consumer interest in terms of gas availability and reasonable tariff for natural gas pipelines and city or local natural gas distribution networks.

Regulatory Bodies

• Petroleum and Natural Gas Regulatory Board

The Petroleum and Natural Gas Regulatory Board Act, 2006 was enacted in April, 2006. Consequently, Government has set up in October, 2007, the Petroleum and Natural Gas Regulatory Board (PNGRB) to regulate the refining, processing, storage, transportation, distribution, marketing and sale of petroleum, petroleum products and natural gas, excluding production of crude oil and natural gas. The aim is to protect the interest of consumers and entities engaged in specific activities relating to petroleum, petroleum products and natural gas and to ensure uninterrupted and adequate supply of these products in all parts of the country and to promote competitive markets and for matters connected therewith or incidental thereto.

Section 11 and 12 of the PNGRB Act, 2006 states the functions and powers

• Directorate General of Hydrocarbon

The Directorate General of Hydrocarbons (DGH) was established under the administrative control of Ministry of Petroleum & Natural Gas by a Government of India Resolution in 1993 to promote sound management of the Indian petroleum and natural gas resources having balanced regard to the environment, safety, technological and economic aspects of the petroleum activity and to review the exploration programmes of companies and advise the Government on the adequacy of these programmes.

Following are the functions of DGH :

"(a) To provide technical advice to the Ministry of Petroleum and Natural Gas

(b) To review the exploration programmes of companies

(c) To reassess the hydrocarbon reserves discovered and estimated by the operating companies in discussion with them;

(d) To advise the Government on the offering of acreages for exploration to companies as well as matters relating to relinquishment of acreages by companies;

(e) to review the development plans for commercial discoveries of hydrocarbon reserves proposed by the operating companies.

(g) To regulate the preservation, upkeep and storage of data and samples pertaining to petroleum exploration, drilling, production of reservoirs, etc.

Questions:

1. Describe the categorisation of oil & gas sector as given in the case above.

Oil and Gas sector is divided into 3 parts

Upstream

Midstream

Downstream

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 oil sector is also known as the exploration and production (E&P) sector. 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.Exploration activity, prior to NELP, was dominated by public sector firms such as Oil and Natural Gas Corporation Ltd. (ONGC) and Oil India Ltd. (OIL). The sector received a major boost in 1974, when the massive Mumbai High fields were discovered off India's west coast.In addition to the efforts to discover new fields, ONGC, in particular new technologies. Many other policies are introduced by Government of India for growth in indigenous crude oil and gas. Which are in progress and have led to many major discoveries.

Midstream:

The midstream industry processes, stores, markets and transports commodities such as crude oil, natural gas, natural gas liquids (LNGs, mainly ethane, propane and butane) and sulphur. Generally midstream is clubbed with downstream industry.

Downstream:

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 and Propane.

2. List the companies that are included in the downstream sector of the oil & gas industry.

The oil and gas industry is usually divided into three major sectors: upstream, midstream and downstream. The downstream sector commonly refers to the refining of petroleum crude oil and the processing and purifying of raw natural gas, as well as the marketing and distribution of products derived from crude oil and natural gas. The downstream sector touches consumers through products

such as gasoline or petrol, kerosene, jet fuel, diesel oil, heating oil, fuel oils, lubricants, waxes, asphalt, natural gas, and liquefied petroleum gas (LPG) as well as hundreds of petrochemicals.

Midstream operations are often included in the downstream category and considered to be a part of the downstream sector.

1. Reliance  Industries - The Flagship Company of the Ambanis and India’s largest Private Company Reliance Industries is also an Oil and Gas Giant .The Company has seen very sharp growth in the last decade and is diversifying into Retail. With a market cap exceeding $30 billion it is India’s most valued company. The company is also one of the biggest exporters in India with one of the largest petrochemical and oil refining complexes in the world at Jamnager.It recently sold a stake in its valuable Godavari Basin to BP for a whopping $7.5 billion. Extremely cash rich with a horde of more than $15 billion, it has started on empire building through ventures in Finance ( DE Shaw) ,Communications (buying of wireless broadband spectrum),Shale Gas Buys in the USA,Hospitality (Buying up stakes in Hotel Companies).

2. ONGC Corp – With a market cap of Rs. 235,000 crores ONGC ranks 3rd in Oil & Gas Exploration & Production (E&P) Industry globally .It cumulatively produced 803 Million Metric Tonnes of crude and 485 Billion Cubic Meters of Natural Gas from 111 fields. ONGC’s wholly-owned subsidiary ONGC Videsh Ltd. (OVL) is the biggest Indian multinational, with 40 Oil & Gas projects in 15 countries. The company earned a revenue of approx Rs. 20,000 crores with net profit margin of 34% in Dec’10.It holds largest share of hydrocarbon acreages in India & contributes over 79 per cent of Indian’s oil and gas production. Created a record of sorts by turning Mangalore Refinery and Petrochemicals Limited (MRPL) around from being a stretcher case at BIFR to the BSE Top 30, within a year.

3. GAIL India – GAIL (India) Limited, is India’s flagship Natural Gas company, integrating all aspects of the Natural Gas value chain right from exploration to marketing. It emphasizes on clean fuel industrialization, creating a quadrilateral of green energy corridors that connect major consumption centers in India with major gas fields, LNG terminals and other cross border gas sourcing points. With a market cap Rs. 58,000 crores GAIL is expanding its business to become a player in the International Market. . The revenue earned was 24,000 crores (2009-10) with a net profit margin of 11%.The business has achieved laying of Natural Gas high pressure trunk pipeline, LPG Gas Processing Units & Transmission pipeline network, oil and gas Exploration blocks, OFC network offering highly dependable bandwidth for telecom service providers etc. GAIL has been entrusted with the responsibility of reviving the LNG terminal at Dabhol as well as sourcing LNG.GAIL is one of the best performing stocks in the Energy Industry in India in the last couple of years. It is a well-managed fast growing company in one of the best sectors in India with high competitive barriers.

4. Cairn India - With a market cap Rs. 66,000 crores, Cairn India is now one of the biggest private exploration and production companies currently operating in the region. A subsidiary of the British company Cairn, its growth has been nothing short of phenomenal after winning a bid to explore oil blocs in Rajasthan in the NELP. Cairn India’s strategy is to establish commercial reserves from strategic positions in order to create and deliver shareholder value. The company operates the largest producing oil field in the Indian private sector and has pioneered the use of cutting-edge technology to extend production life. The company has set up a Processing terminal in Barmer (Rajasthan) to process the crude from fields. A pipeline has also been constructed to transport the crude from Barmer to Bhogat in the Gujarat coast. The pipeline section from Barmer to Salaya is operational and sales have commenced to Essar, RIL and IOC. Cairn India has recently agreed to be taken over by London listed India’s largest Mining Group Vedanta though the approval is still awaited from the government of India. It is the second largest Oil and Gas private company listed on the Indian stock exchange.

5. BPCL – BPCL is along with HPCL and IOCL, a major distributor of petroleum, cooking gas and diesel in the Indian market The company has a  market capitalisation of Rs. 21,000 crores. on revenues of Rs. 36,000 crores with a net profit margin of 0.5%.The company’s low margins and abysmal stock price performance is due to the government control which forces it to sell at below cost leading to huge losses and curtails capex for growth. Despite noises of liberalization, nothing has come about with increased global crude prices increasing the losses greatly.Bharat Petroleum produces a diverse range of products, from petrochemicals and solvents to aircraft fuel and speciality lubricants and markets them to hundreds of industries and several international and domestic airlines.

6. Indian Oil Corporation Ltd (IOCL) – The company covers the entire hydrocarbon value chain – from refining, pipeline transportation and marketing of petroleum products to exploration & production of crude oil & gas, marketing of natural gas, and petrochemicals. With a market capitalisation of Rs. 75,000 crores, it is in the Fortune ‘Global 500′ listing, ranked at the 125th position in the year 2010. IndianOil closed the year 2009-10 with a sales turnover of Rs. 271,074 crore and profits of Rs. 10,221 crore. Indian Oil and its subsidiary (CPCL) accounted for over 48% petroleum products market share, 34.8% national refining capacity and 71% downstream sector pipelines capacity in India. Indian Oil is currently investing Rs. 47,000 crore in a host of projects. The Indian Oil Group of companies owns and operates 10 of India’s 20 refineries with a combined refining capacity of 65.7 million metric tonnes per annum. Indian Oil’s cross-country network of crude oil and product pipelines, spanning 10,899 km and the largest in the country, meets the vital energy needs of the consumers in an efficient, economical and environment-friendly manner. Like IOCL it is also suffers from government mal-interference and not a good investment.

7. Hindustan Petroleum Corp. Ltd (HPCL – One of the smalled of the major Oil and Gas PSUs with  a market capitalisation of Rs. 11,000 crores. The company owns and operates the largest Lube Refinery in the country producing Lube Base Oils of international standards, with a capacity of 335 TMT. This Lube Refinery accounts for over 40% of the India’s total Lube Base Oil production. It has two major refineries producing a wide variety of petroleum fuels & specialties, one in Mumbai (West Coast) and the other in Vishakapatnam, (East Coast). HPCL’s vast marketing network consists of its zonal & regional offices facilitated by a supply & distribution infrastructure comprising terminals, pipeline networks, aviation service stations, LPG bottling plants, inland relay depots & retail outlets, lube and LPG distributorships. HPCL accounts for about 20% of the market share and about 10% of the nation’s refining capacity. The revenue earned was around Rs. 34,000 crores with a net profit margin of 0.6% in Dec’10.

8. Oil India Ltd.- With a market capitalisation of Rs. 31,000 crores, OIL is engaged in the business of exploration, development and production of crude oil and natural gas, transportation of crude oil and production of LPG. It became a wholly-owned Government of India enterprise in 1981. The revenue earned by the company was 2,400 crores & with a net profit margin of 36% in Dec ’10. Very similar in profile to ONGC it  presently produces over 3.2 million tons pa of crude oil, Natural Gas and over 50,000 Tones of LPG annually. Most of this emanates from its traditionally rich oil and gas fields concentrated in the Northeastern part of India and contribute to over 65% of total oil & gas produced in the region. It has emerged as a consistently profitable international company with exploration blocks as far as Libya and sub-Saharan Africa.

9. Petronet LNG Ltd. -  It was formed as a Joint Venture by the Government of India to import LNG and set up LNG terminals in the country, it involves India’s leading oil and natural gas industry players. The promoters are GAIL, ONGC, IOCL & BPCL. The company has a Market cap Rs. 9,000 crores. The revenues earned in Dec’10 was approximately Rs.3,600 crores with a net profit margin of 5%.

Other companies which deserve a mention are Essar Oil,Essar Energ,Aban Offshore,Chennai Petroleum,Gujarat State Petroleum,Indraprastha Gas,Gujarat State Petronent LNG

3. Highlight the tax incentives and fiscal incentives provided by Government of India to new refineries.

Given that tremendous opportunity for investment exists in refining & marketing segments in the coming years, private sector companies including the foreign companies are likely to set up their projects in these segments. Further, the closure of small refineries in North America and Europe due to high compliance costs along with difficulties in obtaining permits for Greenfield refineries in these regions due to environmental concerns is expected to result into large capacity additions in emerging countries like India. While the total investment in refining is estimated at around US$ 60 bn by 2025, the investment in marketing infrastructure during the same period is estimated to be around US$ 32.0 bn.

Tax as well as other fiscal incentives (such as providing SEZ status) provided by the government to new refineries are also expected to have a positive impact on the Indian refining industry. However, the muted export demand due to global economic slowdown will continue to affect the refining sector in the current fiscal.

The new RPL refinery, for example, benefited from its Special Economic Zone (SEZ) status. However, current tax holidays would not be available to non-public sector refineries that commence activities after April1, 2009. In the interim, India does have a number of other viable advantages such as its favourable location, lower construction and operating costs etc. However, given the current economic crisis, some analysts feel that export markets for all the products produced by the Indian refineries may be difficult to come across.

4. Discuss the policies and regulations implemented by the Government to regulate and develop the oil and gas sector.

Over the years various policies have been implemented by the Government to regulate and develop the oil and gas sector. The Petroleum Act to control issues relating to import, transport, storage, production, refining and blending of petroleum was already in place since 1934. Further, the Oil Fields (Regulation and Development) Act, 1948 and the Petroleum and Natural Gas Rules, 1959 provided regulatory framework for domestic exploration and production of Oil & Gas

A. Hydrocarbon Vision :

The Hydrocarbons Vision 2025 lays down the framework which would guide the policies relating to the hydrocarbons sector for the next 25 years. Issues such as E&P, refining, marketing, external policy, oil security, tariff and pricing, and restructuring and disinvestment are addressed by the Group, to ensure that an optimal mix of energy resources are made available to the consumer at the right price. The Hydrocarbons Vision 2025, no doubt, spells out the government's strategy and operational style with regard to this vital industry.

B. Eleventh five year plan:

Availability and access to energy are considered as catalysts for economic growth. The envisaged growth of the economy at 9% in the Eleventh Plan cannot be achieved without a

commensurate increase in the availability of energy. The current level of production barely caters to 26% of the petroleum products demand and the balance oil requirements are met by importing the crude.

C. NELP (New Exploration Licensing Policy)

Prior to the NELP, the Oil fields (Regulation and Development) Act, 1948 and Petroleum and Natural gas Rules, 1958 regulated the issue of license and PSU's. ONGC and OIL were the only public sector companies involved in exploration and production till 1997 while IOCL was the primary entity concerned with refining and processing oil after extraction. "The discoveries made under the NELP have resulted in in-place hydrocarbon reserve accretion of a staggering 642 million tonnes of oil and oil equivalent gas, a total of 87 oil and gas discoveries have been made in 26 blocks under NELP during this period.

D. FDI in Oil and Gas Sector

The sector is fully open to foreign direct investment with 100 per cent equity through automatic route, subject to sectoral regulation that is equally applicable to domestic and foreign players. In Refining FDI up to 49% in case of Public Sector Undertakings, without involving any divestment or dilution of domestic equity in existing public sector undertakings FDI up to 100% in case of private companies.Since Government of India's liberalisation policy, domestic as well as foreign companies have invested Rs.99714 Million during 2004-05 to 2009-10 in oil & gas sector.

E. Policy for Change in Price of Petroleum Products

In line with the recommendations of a High Level Expert Group headed by Dr. Kirit Parikh the Government is in the process of establishing a viable system of pricing of petroleum products. The Government has decided, consequent to a meeting of Empowered Group of Ministers held on 25th June, 2010 that the pricing of petrol and diesel, both at the refinery gate and the retail level, will be market-determined. However, it is proposed that increase in prices of diesel will be staggered over time to minimize the overall impact on the poor and the vulnerable. It has also been decided that in case of a high rise and volatility in international oil prices, Government will suitably intervene in the pricing of petrol and diesel.

F. Policy for Development of Natural Gas Pipelines and City or Local Natural Gas Distribution Networks.

The natural gas sector is at the threshold of rapid growth in the country. With increased exploration efforts under NELP, large scale discoveries of gas in the East Coast, commissioning of the LNG import terminals in the West Coast, projected upcoming LNG terminals and the Government's initiatives in natural gas through transnational pipelines, there is an imminent need to provide a policy framework for the future growth of the pipeline infrastructure in the country with a view to facilitating the evolvement of a nation-wide gas grid and the growth of city or local gas distribution networks. The objective of the policy is to promote investment from public as well as private sector in natural gas pipelines and city or local natural gas distribution networks, to facilitate open access for all players to the pipeline network on a non-discriminatory basis, promote competition among entities thereby avoiding any abuse of the dominant position by any entity, and secure the consumer

interest in terms of gas availability and reasonable tariff for natural gas pipelines and city or local natural gas distribution networks.

5. Write a brief note on the FDI in Oil and Gas Sector.

Over the past decade, India has seen various sectors grow within the country. Starting from the services sector (which makes up about 23 percent of the country’s total foreign direct investment (FDI)), India also experienced growth in the following sectors: computer software and hardware (8 percent), telecommunications (8 percent), housing and real estate (7 percent) and construction activities (7 percent). In addition, the power and oil & gas industries also present significant opportunities for foreign investors looking to get their foot in the door of the Indian market. Given the expanding economy, energy demand is predicted to increase five-fold over the next 25 years, creating a huge potential for returns on investment in these fields.

In this update, we will examine three key sectors for FDI in India: telecommunications, power and oil & gas.

Facts and figures:

Oil & gas sector’s share of FDI inflow: 2.83 percent (petroleum and natural gas) Constitutes over 15 percent of India’s GDP The government is considering a series of tax holidays, including a seven-year tax break, to

assist with the development of exploration in its oil & gas sector to lessen its dependence on imports

The Investment Commission of India states that total opportunity in the oil & gas sector reached US$35-40 billion in 2012

Investment opportunities:

Petroleum products; Improved oil recovery and enhanced oil recovery techniques; Crude oil production from the deep water block; Use of improved technology; Extended oil field acquisition activities; Capacity utilization of refineries; Foreign company collaboration; End-user market and infrastructure development; Setting up oil and gas courses at universities and training institutes; and Opportunities for world-class service providers.

FDI Policy:

Allowing 100 percent FDI in private refineries through the automatic route and 26 percent in government-owned refineries; and

100 percent FDI is also allowed in petroleum products, exploration, gas pipelines and marketing/retail through the automatic route.

Key Indian players:

Indian Oil; Bharat Petroleum;

Oil and Natural Gas Commission (ONGC); Reliance Industries; and Essar

Recent FDI projects

BG Energy Holdings will set up three wholly owned subsidiaries in Andhra Pradesh, Karnataka and Tamil Nadu with around US$28 million investment in each for setting up gas distribution and transmission infrastructure over the next several years.