LNG Terminal Expansion Plans

Inherent issues need to be addressed to meet capacity enhancement targets K. Ravichandran, Senior Vice President, ICRA Limited

A spate of project announcements with respect to new regasified liquefied natural gas (RLNG) terminals in India has been the cause for a lot of exuberance in recent times. Even by a conservative estimate, India should have 10 RLNG terminals with a capacity of 70 million tonnes per annum (mtpa) by 2024, up from the current level of 35 mtpa from five terminals. In addition, another 10 onshore/floating storage regasification unit terminals are also being talked about.

While most of the terminal sponsors justify their business case by pointing to the declining domestic gas production and inadequate incremental gas production to cater to the unmet and new demand, certain questions seem uppermost. Is the market potential high enough to accommodate all the terminals? What would be the challenges and opportunities for the new terminals? While ports will be the key beneficiaries in terms of incremental cargo and revenues, concerns about key success factors for housing the regasification terminals still remain.

Current and projected supply scenario

Domestic gas production, available for sale, steadily dwindled from 113 million metric standard cubic metres per day (mmscmd) in 2011-12 to 68 mmscmd in 2016-17, before staging a minor recovery to 71 mmscmd in 2018-19. While the steep fall in gas production from the Krishna-Godavari (KG)-D6 field is well documented, a fall in production from the ageing fields of government-owned upstream companies also contributed to the decline in domestic gas availability.

Looking at the supply scenario for the next decade, according to ICRA’s best-case scenario, incremental gas production could be around 45 mmscmd, with gas flowing from the development of new discoveries in the existing basins such as the Oil and Natural Gas Corporation’s (ONGC) B and C clusters, Daman offshore, KG-DWN-98/2, the Deendayal block and redevelopment of Mumbai High North and South Phase III; Reliance Industries Limited (RIL)-BP’s KG-D6 satellite fields; Oil India Limited’s Northeast fields; and Cairn India’s Barmer satellite fields; besides the upside from smaller fields such as those of Indus Gas/Focus Energy and Hindustan Oil Exploration Company Limited .

Moreover, the production of coal bed me-thane could also improve after years of under-performance with an upside anticipated from RIL, ONGC and Essar Oilfields Services India Limited. Some upside can also be expected from the recent Discovered Small Fields auctions and Open Acreage Licensing Policy auctions. That apart, the recent spate of reforms in the upstream sector – providing pricing and marketing freedom, reducing fiscal levies and providing a different contractual framework – should offer some comfort for incremental gas production. However, most of the potential from the new initiatives will be back-ended by the long gestation period involved in exploration and developmental activities and the challenges involved in getting statutory approvals in a timely manner.

In a conservative scenario, the supply potential can be lower than the best-case scenario, which could be brought about by the delays in the development of discoveries due to time overruns in projects, approval issues and geological surprises. Nonetheless, in either case, the actual upside could be lower than the current unmet demand and anticipated demand build-up.

Demand-side challenges

Till two-three years ago, the power and fertiliser sectors had been anchor consumers for gas marketing companies as they accounted for almost 70 per cent of the demand, with the rest accounted for by the city gas distribution (CGD), refineries, petrochemicals, steel and other industrial segments.

However, of late, the demand-side dynamics have changed. Demand from the power sector has slumped due to the onslaught of competition from renewable energy sources, notably wind and solar energy, whose tariffs have been less than Rs 2.50 per kWh in the recent auctions. Moreover, with the commissioning of several coal-based thermal power plants in recent years, with some of them not having long-term power purchase agreements, merchant capacity in the industry has increased. As a result, the cost of traded power at the exchanges has been mostly muted. The cash-strapped distribution companies have resorted to traded power rather than committing themselves for a longer period to expensive gas-based or coal-based power.

Accordingly, the incremental demand for gas from the power sector will depend upon how quickly the government is able to implement policies such as procurement of balancing power to offset the infirm supplies from wind and solar, peaking power and time-of-day tariffs for consumers, and gas-based power purchase obligations.

In the fertiliser sector, urea plants have been the primary consumers of gas, with applications for chemicals and complex fertilisers being relatively limited. While six new urea plants are being set up, of which one has been commissioned, incremental demand will be around 15 mmscmd at best, with each plant consuming around 2.5 mmscmd. Furthermore, the growth in urea demand has been anaemic in recent years due to various issues such as 100 per cent neem coating, which is believed to have arrested the diversion for non-fertiliser applications, and the uneven rainfall in different regions. Even while new plants are being set up, there is a likelihood that the new domestic gas could cater to the new urea plants, notwithstanding the marketing freedom given to exploration and production companies, as long as they are cheaper compared to RLNG, as it will help reduce the subsidy for the central government. Besides, any regulatory policy reversals on the offtake of urea from new plants, from which urea will be expensive as compared to imported urea, would be another risk that could impact RLNG demand.

Notwithstanding a challenging outlook for demand from the power and fertiliser sectors, prospects look good for CGD, refineries and other industrial users. The domestic CGD sector has been in the midst of a massive expansion in geographical footprint, following mega auctions under the ninth and tenth rounds conducted by the Petroleum and Natural Gas Regulatory Board, wherein 86 and 50 geographical areas, respectively, have been auctioned. While the demand build-up is slow in the CGD segment, the new geographical areas should collectively contribute over 30 mmscmd of demand over the next decade.

Further, while domestic gas allocation is being provided for in the compressed natural gas (CNG) and piped natural gas (PNG) (domestic) segments, any change in policy on allocation to CNG, as is being talked about lately, will be a positive for RLNG terminals, even while it will reduce the profitability of CGD players and will disrupt their business models. With regard to PNG (industrial and commercial), the demand has to be met from RLNG, as there is a scope for replacing costlier liquid fuels.

On the refineries front, significant potential exists for replacing liquid fuels such as naphtha, high speed diesel (HSD) and furnace oil with RLNG, besides catering to hydrogen production, which is used in various internal processes. While demand per se will keep fluctuating depending on the relative oil and gas price parity, there is significant potential in this segment. Apart from traditional applications, there is good potential for LNG in several new areas, where the replacement of HSD by LNG as a fuel in long distance transportation holds the maximum potential.

Regasification terminal capacity utilisation to decline

Given the price-sensitive demand and several imponderables, utilisation of the new terminals will be suboptimal. Globally, regasification capacity utilisation has been only 35-40 per cent. Even if outliers such as the US where regasification terminals have been rendered redundant due to the shale gas boom, and Japan which has created huge capacity to cater to peak demand (and there exists a huge difference between peak and trough demand), are not considered, utilisation in other regions too has been relatively low at 60-75 per cent.

While Petronet LNG’s Dahej terminal has been operating at more than 100 per cent capacity utilisation, it is more of an exception, given the cost-competitive re-gas tariff and well-developed infrastructure. Utilisation of other terminals is expected to remain low, resulting in weak returns and debt coverage metrics in the initial years. Prudent structuring of loan repayments, take-or-pay commitments to use minimum levels of debt servicing and strong sponsors will be key risk mitigants. Terminals with relatively low capital costs and competitive re-gas tariffs will be better placed to weather some of the challenges.

Ports must look at robust marine infrastructure for maximum revenue potential Given the new RLNG terminals, ports will derive additional income from marine-, vessel-, cargo- and storage-related areas. However, for steady cargo growth, first-mile pipeline connectivity to the nearest trunk pipeline network and successful commissioning of trunk pipelines to all the demand centres will hold the key. Moreover, in view of the increasing capacity of LNG vessels and the matching marine infrastructure needed to handle such vessels, ports would need to ensure deeper draught in the basins and optimum draught in the channels.

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