Gas: The Ground Reality

Views from policy-makers, buyers, sellers and analysts

To focus attention on the changing market equations in the domestic natural gas sector, India Infrastructure, recently organised a two day conference in New Delhi titled, "Arrival of Gas: New Market Equations and regulatory imperatives". The third annual conference, which was attended by more than 180 delegates, was addressed by key people across the sector. The group of speakers - representing the entire set-of industry stake holders - presented the policy issues, buyer and supplier perspectives, regulatory imperatives and fiscal aspects. In this special session we bring you the highlights of the conference and views of some speakers...

Policy -makers

B.K. Chaturvedi
Secretary, Ministry of Petroleum
and Natural Gas

Policy initiatives and issues

• Currently, while gas demand is estimated at around 119 mmscmd, the availability is only 85 mmscmd. After shrinkage and internal consumption, availability slumps to 70 mmscmd.

• This supply constraint forces priority allocation of gas. The highest priority is the transport sector. This means that the full requirement for IGL is met first. The next priority is given to power units, then to fertilizers and public sector units. The rest is pro-rated. The pro-rated sector accounts for 26-27 per cent.

• Priority allocation necessitates massive cuts across various demand sectors. To illustrate, in the Mumbai sector, only 60 per cent of demand is met out of a demand of 16-17 mmscmd. Similarly, the HBJ pipeline system faces a cut of around 26 per cent, subsequent to the Supreme Court order.

• Natural gas is all set to increase its market share to 20 per cent from the present 8 percent. A boost to growth would come from a rise in low energy consumption levels in India relative to peer group countries.

• A number of discoveries have been made in the last two years as a result of NELP. The biggest of these is by Reliance. Other discoveries include Cairn’s and ONGC’s. ONGC has recently taken an initiative to award contracts for deep-sea exploration.

• Coupled with domestic finds are highly probable gas import options. These include gas imports from Myanmar where Gail and OVL hold around 40 per cent stake in the A-1 block near the Indo-Myanmar-Bangladesh border. The estimates are pegged at around 7 trillion cubic feet to 22 trillion cubic feet. Gas from this block could go to Thailand or it could come to India.

• In this scenario of increasing gas demand and supply, the government has planned for new regulations to govern the gas sector.

• Originally, the government had planned a separate act with regulations for the gas sector in line with international trends. However, according to the industry there were too many regulators already. This led to the formation of a common Petroleum Regulatory Board Bill, 2002. The ministry has prepared a draft amendment in the light of recommendations by the standing committee. It is planned to introduce this in the coming winter session of parliament.

• The government has taken three other initiatives. The first is the auto fuel policy, which is round the corner after the Supreme Court’s observations. The second has been the petro product pipeline policy. And, the third development is a draft gas pipeline policy.

• The government will examine the comments of the industry on the pipeline policy. The Reliance gas in the eastern sector, the ONGC and Cairn finds and the Panna-Mukta-Tapti development will all require use of transportation infrastructure to reach demand zones. Shell’s gas must either be linked by a pipeline to Mumbai connecting Hazira to Urban, or it must be linked to the HBJ pipeline. Laying these connecting pipelines will take time.

• The best pipeline policy should achieve three objectives. First, it should achieve the fastest monetisation of the gas that is produced. Otherwise, both producer and new investment will suffer. Second, the consumer must get gas at most competitive prices. Third, availability must be ensured for vital sectors such as transportation, power and fertilizer.

• One of the issues while formulating policy is the existence of unserved areas like Bihar, eastern Orissa and the central region where we are likely to have coal bed methane (CBM). The take-or-pay concept suggested by pipeline designers may not be feasible while India is in a developing stage. For example, in CBM, who will sign take-or-pay agreements when the pipeline does’t exist? On the other hand, where gas is being explored for, nobody is sure that it will actually be discovered. We need to cover broad areas – north, south, east, west and uncovered areas so that we have at the least, a broad network or a superhighway of gas pipelines. From this superhighway branching off is possible.

• The other regulations in the gas sector relate to price. Gas price is affected by three factors – the basic gas price of the producer, state taxes and transportation costs. On the basis of this formula, it seems difficult to provide gas at less than $3 per mmbtu. Let’s consider two alternative scenarios – when you deliver gas at Delhi and at the pithead, let’s say Hazira itself, where the gas is being produced. At the pithead, delivery comes much cheaper. But transportation costs have to be taken into account. The states have identified growth sectors to arrange resources. The sales tax on gas in Gujarat is around 22 per cent, while in most other states, it’s between 10 and 12 per cent. A third factor is the producer price. A lot of money goes in simply finding out whether gas exists. So, producers have been asking for a remunerative price and incentive price, which will induce them to invest. On the other hand, under NELP, the government has said that the NELP producers could fix prices in accordance with the market. Of course, one can argue what exactly is the market. Is it the control market of Rs.2,850 per mcm (thousand cubic metres), which is ONGC’s? Or is it the market price offered to some old PSUs, where prices are around $3 per mmbtu? The regulator must ensure that producers do not overcharge and the prices are fixed at levels that suit the power sector.

Seller's perspective

C.K. Koshy
Chairman, GSPC

The demand-supply gap

• Natural gas is expected to be the fastest growing component of global primary energy consumption. While global consumption is expected to have an average annual growth rate of 2.8 per cent through 2001-25, Indian growth is projected to be much higher at 6.1 per cent through the same period.

• India consumed only 0.8 trillion cubic feet (tcf) of gas in 2001, out of global consumption of 90 tcf. By 2025, Indian consumption is expected to reach 3.4 tcf. In 2001, Indian per capita consumption was 0.3 mtoe against the global average of 1.4 mtoe per capita.

• The key demand drivers will be the pace of economic growth including liberalisation reforms, industrial buoyancy, power and fertiliser sector growth and the facility of foreign investment; pricing of gas including the dismantling of APM and hidden controls; a pipeline grid based on common carrier principle; and a regulatory mechanism.

• The demand-supply gap can be bridged through LNG imports, new domestic findings, CBM, gas hydrates and transnational pipelines.

• In LNG imports, by 2004, Petronet will be receiving supplies of 7-8 mmscmd, which will increase to 17 mmscmd by 2005. Shell will also provide 9 mmscmd by 2005. This will add a total of 26 mmscmd of LNG to existing supplies. The development of LNG at the Kochi terminal by Petronet LNG and the expansion of the Hazira and Dahej terminals can further increase LNG availability by another 26 mmscmd.

• In the domestic sector, Reliance’s find in the KG basin will contribute 30-40 mmscmd. The redevelopment programme at Panna-Mukta-Tapti will fetch another 7-8 mmscmd, Cairn will yield 1.2 mmscmd, Niko 1 mmscmd and GSPC-Niko another 1 mmscmd, totaling 41-51 mmscmd by 2006-07.

• CBM is expected to contribute marginally to gas supplies in the next five years. By 2006-07, it will yield only 2 mmscmd of gas. However, CBM contribution is likely to increase in subsequent years, reaching 10 mmscmd by 2011-12 and 15 mmscmd by 2021-25.

• Indian offshore reserves contain an estimated 1,894 trillion cubic metres of natural gas in the form of hydrates. The MoP&NG has given a fresh impetus to the National Gas Hydrates Programme (NGHP) and studies are being carried out along both the east and west coasts. Though the potential appears high, contribution by hydrates is unlikely in the next five years.

• In the transnational sector, the Oman-India pipeline has been shelved while the Iran-India pipeline project has made no significant progress. Bangladesh-India and Myanmar-India are probable options. However, these pipeline projects involve political issues and the possibility of availability of gas through this route is remote in the next five years.

• All these options are expected to yield a total of 68-144 mmscmd of gas by 2006-07.

• To achieve the hydrocarbon vision objectives, the government in the medium term needs timely and continuous reviews of gas demand and supply options to facilitate policy interventions. It must also pursue diplomatic and political initiatives for import of gas with an emphasis on transnational gas pipelines and also expedite setting up of a regulatory framework. It should import LNG to supplement domestic gas availability and encourage domestic companies to participate in the LNG chain, provide a level playing field for all the gas players and ensure reasonable transportation tariffs, rationalize customs duty on LNG and LNG projects. Moreover, it should put in place an effective organizational structure, which would facilitate progress of the NGHP, operationalise the coal bed methane policy with a time-bound programme, formulate national policy on underground coal gasification in a time-bound manner and increase R&D efforts on conversion of gas to liquids.

• In the long term, the government should review the LNG option in the light of economic, political and energy security considerations. It must exploit the gas hydrates reserves; produce gas from CBM and through underground coal gasification. It should commercialise the production and use of alternative fuels like di-methyl either and the use of fuel cells through increased R&D efforts.

SURESH MATHUR
CEO & Managing Director, Petronet LNG Limited

LNG supply and user base

• The new technologies to cut the cost of supplies on liqufaction, cryogenic transportation and regasification have received a significant breakthrough. It is expected that, as the competition for gas supply grows, LNG imports may compete with pipeline imports for short distance transportations up to 1,500-2,000 nautical miles.

• In the last three years a lot of new developments have taken place in the Indian gas sector. About 70 blocks were awarded for exploration during this period and discoveries have been made. Two terminals developed by Petronet and Shell are at advanced stages of construction.

• The Petronet LNG terminal at Dahej will receive its first cargo in January 2003. It will receive 5 mtpa of LNG at Dahej in phase I and the terminal will be expanded by the same capacity. The Kochi terminal would also be of 5 mtpa capacities in two phases. The required gas pipeline infrastructure to transport regasified LNG is being developed by Gail. The other terminals like Dabhol are also expected to revive soon. The Dahej LNG project is 95 per cent completed and the gas will start flowing by January 2003. IOC, Gail and BPCL will market regasified LNG from the Dahej project for which they have signed GSPA with Petronet LNG.

• Currently, about 6 million tones of naphtha and FO/LSHS are being used by the power and fertiliser sectors because adequate supplies of gas are not available. These units are gas based but since gas is not available they are using liquid fuels. Most of these units will switch over to gas once the regasified LNG is made available. The LNG from the Dahej project will also be used for refineries for fuel as well as generating hydrogen to maximize light and middle distillates. Besides this, gas will also be used as a fuel for captive power generation.

• About 2.5 mtpa of LNG will be consumed by IOC, BPCL and HPCL for refineries to maximize the light and middle distillate yield and also for fuel purposes. It is proposed to extract higher hydrocarbons (C2/C3 and LPG) from LNG, which would amount to about 0.9 mmtpa. Gujarat State Petronet Limited has also requested the allocation of 1 mmtpa of LNG for distribution to local industries and for use in CNG in major cities like Vadodara and Ahmedabad. The surplus LNG would be supplied to deficit consumers.

• Besides, a total deficit of 27 mmscmd exists in the power, fertiliser and other industries. Part of this deficit is currently being met by naphtha and FO/LSHS.

• CNG is emerging in India as a new fuel for the automobile sector and holds a large potential. CNG usage in the transport sector was introduced in major metros like Mumbai and Delhi due to environmental concerns. As of today, about 160 CNG filling stations exist and 175,000 cars, three wheelers and buses are using CNG instead of liquid fuels. There is a total potential for conversion of 1.47 million vehicles in Delhi and Mumbai itself. It is proposed to implement a CNG programme in other cities like Ahmedabad, Vadodara, Kanpur, Lucknow, Pune and Hyderabad.

• The pricing of LNG is crucial in a developing market like India. Petronet LNG Limited has developed facilities at most competitive costs. The price of LNG offered from the Dahej terminal will be a benchmark and affordable by all the sectors.

R.P. Sharma
Head, LNG Business,
Reliance Industries Limited

Exploration and supply

• RIL has bagged 25 of the total 70 blocks awarded under the three rounds of NELP bidding. It has a total of 32 blocks under exploration covering 288,000 sq.km.

• The discovery of natural gas off the Andhra coast by Reliance has made available 14 tcf of natural gas. One 2,000 sq.km of the total acreage explored can produce over 60 mmscmd. The find will increase energy security by creating a large domestic resource, which reduce the import burden, ensures reliable energy supply at affordable prices and environmental protection.

• Discovery of gas on the eastern coast by parties under NELP would accelerate the pace of exploration.

• Success of the upstream segment is dependent on an efficient mid-stream segment. Poor mid-stream performance can result in non-supply to downstream customers due to selectivity of network. High costs of transportation due to a monopoly would result in penalising the consumer. Therefore multiple pipelines or multiple promoters should be allowed.

• Reliance proposes to lay 2,600 km of gas pipelines comprising the ones connecting Kakinada-Hyderabad-Uran-DPC (1,460 km), Uran-Hazira-Ahmedabad (500 km), Kakinada-Visakhapatnam (165 km) and Vijayawada-Ennore (475 km).

• Depending on the source of gas as well as the producer, gas prices vary. For gas sourced from the Ravva fields and sold by ONGC, the price is Rs.3,575 per mcm. Add to this the transportation charge of HBJ at Rs.1,200 per mcm and the total cost is Rs.4,775 per mcm (about $2.8 per mmbtu).

• The same gas sourced from the Panna-Mukta-Tapti fields is supplied at Rs.5,800 per mcm and including the transportation charge adds up to Rs.7,000 per mcm or $4.13 per mmbtu.

• In the case of the KG basin D-6 discovery, 97 per cent of profits will remain inside India as the foreign partner, Niko Resources, holds only 10 per cent stake.

Marc den Hartog
Director, Shell Gas & Power, India
An overview of LNG

• Developed gas markets are mostly supplied from a combination of domestic gas, LNG and sometimes international piped gas.

• India is ideally placed geographically to benefit from a balanced mix of supplies. LNG can usually be developed faster than international pipeline deals because of its inherent flexibility. It is the best mode for enabling intermediate storage. LNG is best able to adapt to changing international circumstances. LNG supply and receiving capacity can be increased very fast, once basic infrastructure is in place. It also offers additional benefits in terms of technology transfer and spin-offs. It is also usually easier and quicker to finance LNG.

• LNG will help develop the Indian market in 2004, providing strong stimulus for further infrastructure development and providing synergies for a growing networked supply system.

• In 2002, there was a total worldwide LNG demand of around 130 mtpa. In 2002-03, there were around 140 LNG vessels. The world LNG shipping tonnage was 14.5 million cubic metres in 2003, vis-à-vis 7 million cubic metres in 1991.

Buyer’s perspective

C.P. Jain
Chairman and Managing Director,
National Thermal Power Corporation

Gas versus coal

• Let me explain the price sensitivity from the perspective of two major consuming groups. First, the power sector, which consumes around 40 per cent of gas production. A bulk power buyer is charged a two-part tariff consisting of fixed and variable charges. The critical factor is the comparative cost of the variable element. Therefore, in order to determine where to purchase power, the buyer considers two factors. Number one: What is the cheapest source of power available on a day-to-day and hour-to-hour basis? Number two: Assuming that fuel is being bought, what is the final realization price of power?

• Considering both factors, the fuel price (which is almost 60 per cent of the cost of generation) is critical, especially since regulators insist on consistently rationalising consumer prices.

• The fertiliser sector can utilize the option of production at the fuel source, followed by transportation to India. Iffco, Kribhco and RCF have a joint project in Oman. This will buy gas in Oman and brings fertilizer back into India on a back-to-back purchase arrangement. Now, in this scenario, there are no cross-border barriers. The fertiliser sector also has subsidies, but these will not be there for ever.

• However, new discoveries from Cairn, Reliance, ONGC, etc. have changed the dimensions of gas availability, demand and the price sensitivity.

• Natural gas has advantages due to its better conversion ratio and cleanliness. Gas-based power projects are very easy to operate and technologically these projects are much better for meeting peaking demands. But the premium for these advantages must be limited.

• Let’s assume coal to be the competitive fuel for the power sector. While Coal India sells at an average of $14-$15 per tonne, similar coal from South Africa is mined and sold at $6-$7 per tonne. Coal is cheaper than gas and prices re expected to reduce further with new captive blocks becoming operational.

• In terms of coal pricing, the cheapest pithead costs are around 47 paise per unit of power generated. The maximum price is around 64 paise per unit. Consider Talcher. If power is carried from Talcher to Kerala and Tamil Nadu, the transmission costs are no higher than 45 paise per unit. So even if power is generated at 45 paise per unit from Talcher, and transmission costs another 47 paise per unit, the total cost is 92 paise per unit.

• Instead of transmitting power we can carry the coal. For a journey of about 600 km, transportation costs around 68-70 paise per unit. For 1,200 km, it costs around 90 paise and for 1,500 km it costs around Rs.1.05.

• Gail’s gas costs around 90 paise at Anta, 88 paisa at Faridabad, and 91 paise at Auraiya. Power from Kawas and Gandhar might be available at slightly lower costs.

• On average, the current gas price ranges from $2.3 to $2.6 per mmbtu. At these prices, gas supplied by Gail and ONGC is equally competitive.

• The developers of the new discoveries as well as LNG suppliers will have to look at these pricing benchmarks to determine affordability – from the point of view of both sellers and buyers.

• Today, the delivered price of GSPCL including the wellhead price, transmission charges and taxes, is around $4.93 per mmbtu and the ONGC joint ventures are around $4.55 per mmbtu. This translates into fuel costs of Rs.1.70 and Rs.1.57 respectively. Would you rather buy power from a supplier whose fuel cost is 60 paise or from somebody whose cost is Rs.1,70?

• We must also consider coal imports. On the eastern coast, import costs on average come to Rs.1.10, and, on the western coast, to around Rs.1.05.

• In the case of LNG transportation, there are three or four competitive locations, namely, Qatar, Iran, Yemen and Oman. In the case of Qatar, studies indicate that CIF delivery on the western coast of India costs around $1.6 per mmbtu. Taking taxes, transportation and regasification into account, the figure stands at $2.25 per mmbtu. The figures for Iran stand at CIF $1.78 per mmbtu and delivery at $2.44 per mmbtu. For Yemen, the comparable figures are CIF $1.97 and $2.63. Therefore, NTPC fixed a benchmark of $3 per mmbtu, that is, Rs.1.14 in fuel costs.

• The entire value chain must be dealt with on an equal footing. The role of the regulator has to be defined properly. In terms of fuel costs, which are market linked or fuels like coal, which are now being market linked, it is unregulated. But when it comes to fertiliser or power, the regulated pricing places producers under serious stress. Today, NTPC supplies power from Singrauli and Korba at an average of less than Re.1. The market price of that power is Rs.2.40 to supply power at that regulated price, while paying for fuel at market prices or at prices based on some international indices, we don’t benefit the ultimate consumer.

• In fact, the ultimate consumer gets hit by two factors. First, as the fuel cost is a “pass-through”, the consumer is being made to pay higher cost for the power just because the fuel is benchmarked to the “basket of international oils”, in case of gas. Second, when the high cost of fuel affects the dispatchability of a station, finally it is the ultimate consumer who bears the capacity charges for the underutilized capacity.

• Further, taxes and duties, which vary across states, need to be rationalized. Linking the price of gas with a basket of fuel oil is not the right way to go. It could probably be possible where competing fuel is not available. Regarding pipeline policy, pipelines should be available on a non-discriminatory basis and the pipeline operator should not be involved in trading.

D.K. Gupta
Executive Director,
Planning and Development, IFFCO

Urea imports versus local production

• The critical factors for the Indian urea industry are low energy consumption, pricing and availability of feedstock.

• In the fertiliser industry, the retention price scheme (RPS) has been replaced by the group pricing scheme with effect from April 1, 2003. Under RPS, units were paid subsidy equal to the difference between unit-wise retention price and selling price. According to the new scheme, urea plants are divided in six groups based on feed-stock and vintage. Plants are allowed the group average or actual retention price, whichever is lower.

• The fertiliser industry will be monitored till March 2006. Under the present economic reform policy, the industry will endeavor to optimize production cost.

• In case the fuel oil-based plants convert to gas, the demand for gas by the fertiliser producers would reach 52 mmscmd by the year 2007-08. In case they do not, it will be 45 mmscmd. In these projections, agricultural growth is expected to be 3 per cent and the price considered is the present $2.5 per mmbtu which is inclusive of all expenses. It has been assumed that fee-stock constitutes 40-50 per cent of the total production cost.

• If the gas price increases to $3 per mmbtu from the present $2.5 per mmbtu, it will result in an increase in the selling price by 10 per cent and it would be difficult to pass that on to farmers.

• Availability of NG/LNG will facilitiate capacity creation and also the conversion of existing naphtha/FO plants. The average international FOB price from 1998-2002 has been $99 per mt and the landed price has been $138 per mt.

• The average FOB price of urea from OMIFCO, Iffco’s new project in Oman, is expected to be $11$ per mt (effective 2005). The landed cost of imports from OMIFCO works out to Rs.7,031 per mt. The new urea plants can match this price only if natural gas is priced at $2.8 per mmbtu. Only a few fertiliser plants are price competitive with respect to this import parity price.

K.K. Kaul
Executive Director, Shriram Fertilisers

The view from the fertiliser sector

• Nitrogenous fertilizers use hydrocarbons (gas, naphtha, fuel oil and coal) as feedstock. Urea accounts for 82 per cent of nitrogenous fertilizers. There are a total of 32 urea plants with an installed capacity of 21 million metric tones. The total investment in the fertiliser industry is around Rs.250 billion.

• The fertiliser industry is heterogeneous with respect to feedstock, technology and vintage. Gas is the preferred feedstock for urea due to its environment friendliness, ease of operation, relative safety over a broad range of operating conditions, better catalyst life, faster plant start-ups and shutdowns, no storage hazards, lower prices compared to naphtha and fuel oil and lower C02 availability.

• In India, only 48 per cent capacity is on gas against a global average of 72 per cent. The present gas consumption in fertiliser plants is around 22-23 mmscmd. About 85 per cent of gas capacity is located along the HBJ pipeline.

• Around 17 mmscmd of gas is required for changeover of the existing non-gas-based capacity. This shift depends on the changing dynamics of gas composition, prices and supply contracts.

• Under a controlled price regime, energy cost reimbursement is the gas cost after conversion. Therefore, the benefit of lower prices does not accrue to industry. The capital investment for changeover will have to be incurred with no returns.

• Also, due to the government’s emphasis on reduction of subsidy, high-cost production is discouraged. Imported urea is emerging as an alternative to high-cost domestic production. Therefore, gas price has to be competitive and acceptable for subsidy support.

• A fully decontrolled regime increases competition with local low-cost producers as well as with imports.

• Due to the seasonality of fertiliser consumption, the industry requires flexibility of gas sales contracts on take-or-pay provisions. In addition, the producers need assurance on continuous gas supplies and fall-back arrangements. They hesitate to sign long-term contracts because of long-term viability issues.

Market Analysts

Nitin Zamre
Head, Oil and Gas,
CRISIL Infrastructure Advisory

Demand, supply and regulation

• According to Crisil, the incremental gas demand in 2010 should be 116 mmscmd. Western India will account for 52 mmscmd, the south for 42 mmscmd, the north for 18.5 mmscmd and the east for 4 mmscmd.

• The power sector will generate most demand at 57 mmscmd followed by fertilizers at 57 mmscmd followed by fertilizers at 31 mmscmd, stell at 8.6 mmscmd, other industrial segments at 2.6 mmscmd and distribution at 12.3 mmscmd.

• Crisil assumes that the supply form ONGC fields will meet the projects of the Long Term Growth Plan, PLL’s Dahej terminal will reach full capacity of 5 mmtpa by 2006-07, Shell’s Hazira terminal with a capacity of 2.5 mmtpa would become operational in 2005 and Reliance would begin supplying 20 mmscmd of gas from its KG basin filed by 2007-08. The latter will increase to 30 mmscmd by 2010.

• Many issues must be addressed in the proposed petroleum regulatory bill. Some pertain to the role of the regulator. Will the board be really independent with the union government having powers to issue directions to the proposed board? Does authorization by the board pertain to licensing? Is it price regulation regulation by the board to monitor prices to prevent profiteering< Is there a need for a separate regulator or regulatory terms for oil and natural gas? The scope and jurisdiction of the state and union governments’ respective roles, definition of profiteering, specification of authorization norms, coverage of LNG facilities, etc. Other issues relate to preference of the common-carrier regime for natural gas and details of the common-carrier regime.

• Issues in the draft pipeline policy pertain to coverage, choice, tariff determination and role of the regulator. There needs to be clarity regarding coverage of LNG terminals and associated facilities and the policy should provide a clear framework for private sector participation. It should state the rationale for nomination of a notified company, preference of a common-carrier regime and allowance of bundled transportation and trading. It should provide details of rate of return, accounting, and procedural and tariff determination methodologies.

• Regulation from the buyer’s perspective would mean a certainty of gas availability, economic gas pricing, consistent regulatory regime and phased sector deregulation leading to competitive markets.

Regulation

Dr. A.R. Sihag
Director, Regulatory Studies and Governance,

TERI

• The objective of regulation is to secure orderly sector growth and entry control. The role of price is very important. There should be the right kind of pricing signals to stay in the market. If you can find ways of introducing competition then you would move closer to a productively efficient industry. Equity considerations are another important social objective.

• The current regulatory approach is legacy; certain players have market control. The other aspects of regulation are notification of gas prices and production-sharing contracts.

• Looking at the functions of the proposed board under the Petroleum Regulatory Board Bill, 2002, the bill says that it will protect the interests of consumers and entities engaged in the specified activity. This is unique. The objective of regulation is to move to a regime of competition in which creative destruction should take place. If you are going to protect the interests of entities engaged in specified activities there is a lack of clarity on the goals.

• The other pointer is to ensure uninterrupted adequate supply of petroleum and petroleum products in all parts of India. When interpreting this in the regulatory context, this will probably prove too ambitious a goal.

• In the pipeline policy, when we look at the definition of common carrier it only covers pipelines. But there are other infrastructure elements in the downstream petroleum sector, which should be included in the definition of common carrier. For example, compressors.

• The pipeline policy says that if some entity wants to lay a pipeline as a common carrier then it should apply in writing. This in effect, can mean that if an entity is not laying a pipeline as a common carrier, then it is out of the regulatory regime.

• Similarly, there is a dispute about transportation rates. It says, transportation in relation to common carrier means such rates for moving each unit of petroleum or petroleum products as the authorized entity may fix. So there is provision in law which will make it possible for a market to develop capacity of pipelines or, for regulators to use charges for capacity. In infrastructure industries you have two-part tariffs: capacity and usage. Here, the only provision is via the transportation rate, which only applies when gas is moved.

Mohit Saraf
Partner
Luthra & Luthra Law Offices

Legal and regulatory issues

• From a seller’s perspective, the sanctity of contracts is very important. Especially after the Dabhol experience. If the parties understand and decide to find loopholes in contracts then the best negotiated contract can be legally breached.

• A more important aspect is: one cannot discount revenues based on a contract. It is required that the gas sold to a gasification terminal actually reaches the consumer. For this, well-integrated pipelines must be based on common-carrier principle. At the end of the day, the focus is not the SPV selling gas to you, it is the intermediate offtakers like fertilizer and power plants that consume the gas.

• Then there is the taxation regime. Even if you negotiate a long-term contract does not generate any revenue if the consumers refuse to pay high sales tax.

• Another important issue is a level paying field. The drafts are out, but we require another six-eight months for a regulatory regime to be in place. The pricing issue is important with respect to domestic gas versus LNG. The price of gas should be market regulated and not ministry regulated.

• An SPA (sale and purchase agreement) is the agreement by which LNG is supplied in the country. The take-or-pay obligation can be viewed as a penalty and anything which could be viewed as penalty may not be enforceable. So there are legal uncertainties beyond the regulatory framework. The current account convertibility is already given and the take-or-pay obligation should be available without a problem. However, we have seen that the take-or-pay obligation even in a current account transaction does not find favour with RBI and authorized dealers.

• A regasification terminal is an SPV, which has high debt and low equity. Therefore, a seller would look at credit enhancement, which would may the liquefaction frame and exploration facilities bankable. These are expected features of regulation.

• There should be a participatory and conceptual approach to legislation. It should not take several years and should include all stakeholders. The quicker you decide, the more competitive the industry becomes. The petroleum regulatory board bill has to be thought through in much more detail because one purpose is also to protect incumbents.

• In the draft pipeline policy, interstate pipelines would be managed by Gail till such time the government notifies a new agency. If it takes, say, three years to unbundled Gail, we are really talking about three years of common-carrier principle. The most important thing is there should not be common ownership. In three years, the incumbent player would acquire a stronger monopolistic position. Crossholding tantamount to unbundling.

• Even with a long-term SPA, arbitrators can assuage restrictions. This will definitely make everybody nervous; both suppliers and consumers. It should be clearly carved out that if parties decide to resolve disputes at a certain forum, that forum should be adhered to and respected.

• Multiplicity of regulation is also an important issue. There should be convergence of regulators. With the Gujarat Gas Act vis-à-vis central petroleum regulator and all such issues, we are getting a multiplicity of regulators.

• The independence of the regulator is another critical issue which we need to look at even more because the incumbent is the dominant player. The regulator has to stay away from government and look after the interests of the sector.

Ranajit Banerjee
Associate Director, PWC

Key regulatory issues

• Gujarat has significantly constrained demand for gas. Pipeline infrastructure is a major constraint.

• There is a need for a gas sector development plan which would include creating transparent markets of domestic gas and LNG, planning a network to improve access to end-users, ensuring that pipelines follow “common carrier” principles so that gas finds its economic value.

• There is need for a regulatory framework which should include bringing about a stable regime for the gas sector, regulating transmission charges following international best practices, creating a licensing framework for “exclusive” distribution zones for retail and ensuring a strong watch over monopoly powers. It should also ensure adoption of health, safety and environmental (HSE) norms.

• Gujarat has taken legislative action. The Gujarat Gas Act recommends transmission for specified companies and an independent regulatory authority. GSPL is driving transmission capacity growth. Gujarat initiated an interim gas policy for promoting investment in local distribution projects. This has received good response in all circles.

• The key issue in regulating or deregulating gas distribution is a natural monopoly. The economics of distribution is crucially linked to the ability to make trading profits on large loads against competing fuels. Domestic consumers alone are not economical. The economics of retail distribution is linked to low-priced domestic gas.

• The key issues in regulating transmission relate to the unbundling of Gail for HBJ (will it offer equitable access to Shell and other NELP producers ?), Dahej-Uran pipeline (access to Shell from Hazira, access to NELP/JV producers, will this be on a take-or-pay basis ?), the national gas grid (built by whom ? Common carrier or contract carriage? Whose gas? What tariff? Who pays for surplus capacity?) and access of offshore ONGC networks to NELP/joint venture producers.

• In the draft pipeline policy “common carrier” is not defined. Plus, the monopoly of Gail over transmission sends wrong signals and will restrict investments by others.

• Whose baby is CNG? Is it the government’s responsibility, or the transmission or distribution company’s ? Which department of the government controls it? Does transport or energy receive priority? Who enforces CNG conversion? Who develops CNG stations? Is there need for state-specific CNG acts? All these questions must be answered.

• The arrival of LNG creates a paradigm shift. Who will use LNG terminals? Are they monopolies? If so, for how long? Why not delink LNG terminals from the LNG value chain? Should’t LNG terminals be common-user facilities with published tolling charges?

Fiscal

Mukesh H. Bhutani
Partner, Ernst & Young

Rationalising taxes and duties

• The price of gas is an important element in demand-supply dynamics given the delicate balance between demand and supply.

• The need of the hour is a stable, rational fiscal regime. Taxes have a significant impact on prices. While there is a 10 per cent custom duty, 4-20 per cent of sales tax and 35 per cent of income tax on natural gas, capital goods invite 26.6 per cent customs duty and 16 per cent excise duty.

• Hydrocarbon Vision 2025 talked about providing a level playing field for all gas players and rationalized customs duties on LNG and LNG projects. In NELP rounds I to IV the fiscal terms have been improved. These include a tax holiday, removal of cess, royalty on an ad valorum basis and exemption of customs duty on capital goods. The proposed Integrated LNG Policy deliberates tax concessions to make LNG competitive. The Shankar Committee recommended lowering of sales tax on gas to keep prices of landed gas as low as possible.

• Going forward, the cascading impact of taxes on fuel prices needs to be eliminated. There is a need to ensure a level playing field for domestic and imported gas and to promote natural gas as the fuel of the future.

• The options to achieve these imperatives include classifying natural gas/regasified LNG as a declared good, giving infrastructure status to natural gas projects and rationalizing duties on project imports.