The Indian government intends that natural gas will become a far bigger proportion of the mix of domestic energy consumption in the future. Currently, gas (both imported and produced) forms just over 6% (or 58 Bcm for the year 2017-2018) of the energy requirement, with recent government policy statements envisages this to rise to 15% by 2030.
Source: BP Statistical review of World Energy 2018
Major investment in production from offshore gas fields (see below) is one element in the official plans, but is insufficient to meet demand.
Intergovernmental talks have been going on for years on major gas pipeline projects (from Oman, from Iran via Pakistan) but the progress has been snail-like. There are major geopolitical considerations which are impeding progress. So, the keystone to the policy is intention is to fill this energy gap by extending significantly LNG imports. Historically, Qatar has been the predominant supplier.
With the present LNG import of around 20 MMt/a, India is world’s fourth largest buyer, after Japan, South Korea and China. The plan to raise the share of natural gas will require a vast increase in imports and construction of more LNG terminals.
Diversifying sources of LNG imports
In 2012, state-run gas marketer Gas Authority of India Ltd (GAIL) signed a 20-year agreement with Russia’s Gazprom for the purchase of 2.5 MMt/a LNG. In June 2018, the first LNG cargo from Russia was delivered to the Dahej terminal in Gujarat.
Supplies have also started from the U.S. In March 2018, Cheniere Energy announced that it had a 20-year LNG supply to GAIL from the Sabine Pass liquefaction facility. The agreement for the supply of 3.5 MMt/a was signed in December 2011. GAIL’s Chairman stated that “GAIL is one of the foundation customers of Cheniere, having signed the contract in 2011. With supplies commencing from the U.S., GAIL will have a diversified portfolio both on price indexation and geographical locations”. LNG contracted by GAIL under the long-term deal with Cheniere Energy is priced at 115% of Henry Hub prices plus a fixed cost of US$ 3 / MMBtu. GAIL has also contracted to buy 2.3 MMt/a over 20 years from Dominion Energy’s Cove Point liquefaction facility.
Over the last three years, GAIL and state pipeline authority Petronet have reworked contracts with suppliers from the Middle East, Russia and Australia, reducing the negotiated price and increasing delivery flexibility.
At present, India has four LNG receiving terminals. All are on the west-coast: Petronet has a 15 MMt/a terminal at Dahej, and a 5 MMt/a terminal at Kochi; Shell has the 5 MMt/a terminal at Hazira; Ratnagiri Gas and Power operates the 5 MMt/a Dabhol terminal.
According to government spokesperson Narendra Taneja, the plan is to build no fewer than eleven new LNG terminals over the next seven years, to increase the import capacity to more than 70 MMt/a.
One of the first of these is expected to be commissioned later this year: Indian Oil Corp Ltd’s (IOCL) Ennore terminal in the south-eastern state of Tamil Nadu. This will be first LNG terminal on the east-coast and will have a capacity of 5 MMT/y.
In July 2017, construction work started on Dhamra LNG terminal on the east-cost in the state of Odisha. Dhamra will be the second LNG terminal on the east coast, and will have an initial capacity of 5 MMt/a which may be doubled to 10 MMt/a. Some 3 MMt/a will be used by IOCL, 1.5 MMt/a by Gas Authority of India Ltd (GAIL) and the remaining capacity will be available to other industrial users. The project, expected to be in operation by 2020-21, is being developed by Adani Group (50%), IOCL (39%) and GAIL (11%). The terminal will be connected to city gas and industrial customers with a 2,540km pipeline, including the metropolis of Kolkata.
The construction of Mundra LNG import terminal on the west-coast is reported to have been completed and the plant is expected to come on-stream by late 2018-2019. The project, which has a capacity of 5 MMt/a, is a JV of the Adani Group and Gujarat State Petroleum Corp Ltd (GSPCL). The pipeline connection to the terminal will send out gas to Gujarat’s main grid, critical for commercial operations.
The state-run Hindustan Petroleum Corp Ltd (HPCL) has formed an equal JV with Shapoorji Pallonji Port Pvt Ltd to build a 5 MMt/a capacity LNG terminal at Chhara Port on the west-coast. In addition, the Jaigarh LNG terminal in Maharashtra is being constructed by Hiranandani Energy, which has signed a contract with a US-based firm that wants to bring its own gas through this terminal.
Operations are also underway at existing facilities to enhance their output. While Shell at Hazira and Petronet at Dahej are planning to double the capacities, the completion of a breakwater project at Dabhol, along with pipeline connection at the Kochi, will see the Dabhol terminals operate at maximum capacity.
An aggressive approach to raise domestic production – the deep-water Krishna-Godavari Basin to be the key
With emphasis on importing more LNG from new sources, and investing in developing infrastructure, state-run ONGC and a major private player Reliance Industries Limited (RIL) are investing heavily in the deep-water Krishna-Godavari (KG) Basin.
RIL and JV partner BP announced in June 2017 that contracts will be awarded to progress development of the ‘R-Series’ deep-water gas field on the KG-DWN-98/3 (D6) deep-water block. This is first of three planned projects (Satellite and MJ-1 discovery being the other two projects) that are expected to be developed in an integrated manner, producing from about 3 Tcfg resources (in place or recoverable). Development of the three projects, with total investment of around US$ 6 billion (INR 40,000 crore), is expected to bring a gas production from this acreage to 1 Bcfg/d, ramped up over 2020-2022.
In March 2016, ONGC approved the Field Development Plan (FDP) for Cluster 2 on the KG-DWN-98/2 deep-water block, for a project cost of US$ 5 billion. The project is expected to produce cumulatively around 183 MMbo and 1.5 Tcfg, with peak production of 78,000 bo/d and 529 MMcfg/d. ONGC expects to bring first oil and gas from this project to market by late 2019. Cluster 2A’s peak production is pegged at around 78,000 bo/d plus associated gas (105 MMcfg/d), while Cluster 2B’s peak output is touted at 450 MMcfg/d.
In terms of consumption of the domestic gas, ONGC and RIL have started discussions with potential industrial customers in west India to supply them with gas expected to come on-stream in the next three years from the Offshore KG Basin. RIL is reported to be offering contract durations of three, five, and ten years. The companies are planning to use Reliance’s 1,375km pipeline which was built in 2009, connecting Kakinada in the east of the country to Bharuch in the west. The pipeline has been operating under-capacity in recent years due to a decline in production from RIL’s D1-D3 field in the KG Basin.
The government’s serious attempt and planning of a move towards increasing the use of natural gas in energy consumption is surely a path in the right direction. Backed by not just the financial commitments but also making use of technology from the likes of BP in the KG Basin, can certainly deliver results. However, in the past, execution of such effective plans has seen some delay in the country. But given the already vast middle classes grow in numbers, and consumer demand rises, execution of such plans will be crucial for India’s growth story.
Recently, we were able to analyze the 2016 status report from The International Group of Liquefied Natural Gas Importers (GIIGNL) regarding the advances of the industry of Liquified Natural Gas (LNG) at the global level. Here are some facts, reflections and an analysis of the impact in the gas equation of the Southern Cone.
To start, we can confirm that the future of natural gas is intimately tied to the objectives and terms of Paris’ COOP over climate change. It is not possible to get close to the objectives set without increasing the use of natural gas to replace coal in the generation of electric energy, petroleum and its derivatives in the transport segment, and elsewhere where LNG and the Mini LNG can play a predominant role.
LNG is becoming more relevant in the supply and demand of natural gas at a global level. At the end of 2015, 34 countries imported purchased LNG compared to 15 countries in 2005. The demand for LNG increased to 2.5% in 2015 compared to 2014, even with the reduced demand in the global economy.
Why is LNG preferred over pipeline gas? First, the costs involved with liquefying, storing and regasifying are being reduced significantly and made more modular (Mini LNG). Secondly, because it’s an abundant source. Third, because more transactions are done on in the spot market and no longer require long-term contracts as a sole option. Almost 30% of the global LNG transactions are completed in the spot market and short term, and it’s turning the product into a commodity.
Contracting LNG on the spot market or short term (though there may be higher pricing available depending on the supply and demand) helps buyers avoid dealing with tedious clauses buying in “take or pay” contracts, that can facilitate the electrical business in particular. Flexible gas is the industry name for this type of natural gas.
Additionally, in South America, LNG complements the generation of hydroelectric very well, and larger importations can be quickly made available if there is not sufficient rain. At various times you will notice countries are importing or will start importing more LNG such as Brazil, Chile, Argentina, Colombia, and Uruguay.
It is interesting to note that in the countries that are just starting to develop LNG prefer the Floating Storage Regasification Units (FSRU) more than previously developed countries. These are ships that receive, store, and regasify the natural gas and can be transported and used in other places, leaving behind fixed installations. I am sure that it has something to do with the security jurisdiction of the countries. Brazil has 3, Argentina 2, Colombia 1, Uruguay will have 1. Meanwhile, Chile has two existing terminals on land but the third that is being studied in the south is an FSRU.
On the demand side, we have the debut of the first project of Floating LNG in Australia. It’s without a doubt a technological breakthrough for a ship to produce gas, to liquefy it, to store it, and to permit it being transported off the ship to other ships of LNG. There are two more in construction, and certainly there will be more projects in the years to come.
With 5 new land-based liquefaction projects entering in production between 2016 and 2018 along with abundant shale gas, the USA will position themselves ahead of Qatar as the largest producer of flexible LNG in the world and will increase demand in the basins of the Atlantic and Pacific. By 2019, USA will have 9.6 billion cubic feet per day to export (9 times the volume of the Bolivia/Brazil contract at maximum capacity). Australia also has new capacity for liquefaction in the Pacific being deployed to Malaysia as the third-place producer of LNG. USA, Qatar, and Australia will own the majority of the LNG market up to the year 2020.
Current oversupply and lessened economic growth makes us think in two to four years we will have more oversupply of LNG in the world and that the producers will become more aggressive to take new markets in “take or pay” and spot and without a doubt achieve better pricing than the past decade.
As previously mentioned, imported LNG will bring on new markets and more regasification will continue to be installed along the coastlines of South America. There’s no question Argentina, Brazil, Bolivia, Perú, Colombia and Venezuela will have to increase gas storage and integrate with even more with pipelines. Though the potential gas in all of these countries is very abundant, there is a marked exploratory deficit to supply the demand, and that’s why imported LNG should happen more frequently.
If we take average JKM prices (7.4 USD/MMBtu) of imports through the Pacific, and average NPB prices (6.5 USD/MMBtu) in the Atlantic in 2015, and we multiply it by the true imported volume of LNG from Argentina, Chile and Brazil, we land at approximately at $4,190 MMUSD in imports that perhaps should have stayed in the Southern Cone.
These billion-dollar projects are breaking up the regional energy sector, and everything indicates that new LNG regasification plants will continue to increase, and exploration will continue to lag.
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The shale gas revolution has allowed the State of Texas – and our nation – to achieve a level of unprecedented energy independence. With the expansion of liquefied natural gas (LNG) exports – an abundant and clean energy resource, our country stands to achieve substantial economic opportunities, while more than meeting our need for energy both at home and abroad.
LNG, the same natural gas used by more than 65 million Americans to heat their homes this winter, is natural gas converted to a liquid state in order to be safely and efficiently transported. LNG facilities, have been operated safely for more than 50 years, with an environmentally- and economically-sound record that remains the envy of other transporters of petroleum products.
In the early months of 2013, ICF International, a global professional services firm, conducted a nonpartisan study to determine the economic impact of LNG on our nation’s economy and its effect in driving economic development in exporting communities. ICF’s study revealed that the LNG export industry could bring up to 155,000 jobs to the State of Texas by 2035, injecting tens of billions of
dollars into our economy while enhancing the local tax base that funds schools, parks and other valuable public works and services in our communities.
But LNG export terminals are long-term ventures requiring significant capital investments. In recent years, only five LNG export facilities have been approved or commenced the pre-filing process with the Federal Energy Regulatory Commission (FERC), representing a combined capital investment that could exceed $40 billion. Clearly, this is a great opportunity for Texas.
Not only are LNG export facilities poised to drive economic development in Texas communities, they will also advance U.S. national security interests by providing clean, safe energy to our allies abroad.
Throughout the world, many of America’s allies are at the mercy of countries hostile to our interests to provide the energy needed to drive their economies. Exporting a small percentage of America’s vast supply of natural gas will not only narrow our trade deficit by billions of dollars and help our allies meet their need for clean energy and reduce their dependence on nations that do not share our values.
Because of technological and industrial advances in the energy sector, the United States, with the help of the State of Texas, possesses enough natural gas to meet domestic demands in addition to the needs of the global market. Exporting a portion of our excess supply in the form of LNG will help U.S. allies combat energy challenges and diversify their energy resources, yielding a positive impact on our nation’s economy, international relationships and trade balance. By exporting LNG, the State of Texas has the opportunity to become the global hub for providing a source of clean, safe and reliable energy.
Ultimately, LNG exports will yield significant economic benefits for Texas while also helping our friends abroad.
Oil and gas exploration is one of Texas’ most established and valued industries, and the Lone Star State still stands to benefit from further diversifying its energy production.
While LNG export is a new industry in the State of Texas, it represents a clean, safe energy resource for future generations. Expanding LNG exports will not only significantly increase energy output; it will bring billions of dollars of capital investment to our state, create thousands of jobs and yield millions of dollars in tax revenue while advancing our national security interests and providing opportunity and to Texas communities.
There is much to be gained from expanding LNG exports in the State of Texas. We have a unique opportunity to positively contribute to the economic development of our state, and it’s an opportunity we simply don’t want to miss.
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Even as natural gas overtakes coal as the biggest U. S. electricity source, the U. S. Gulf Coast is set to become a major export hub for the international Liquefied Natural Gas (LNG) business. A quick look at the existing Federal Energy Regulatory Commission (FERC) approved facilities indicates that 6 out of 11 (55%) of them are located on the Gulf Coast. Many of these facilities were originally built as import (re-gasification) terminals, but with the incredible rise in U. S. shale gas reserves and production, they have been re-engineered to export (liquefaction) terminals.
Existing FERC Jurisdictional LNG Import/Export Terminals (Source http://www.ferc.gov/industries/gas/indus-act/lng.asp)
A check of the FERC “approved” facilities shows 9 of 11 (82%) located on the Gulf. More importantly, 4 out of the 9 Gulf sites are currently under construction (Sabine Pass, Hackberry, Freeport, and Corpus Christi).
Reviewing the “proposed” FERC facilities, 16 out of 24 (67%) find their home on the southern coastline.
Sources http://www.ferc.gov/industries/gas/indus-act/lng/lng-approved.pdf and http://www.ferc.gov/industries/gas/indus-act/lng/lng-export-proposed.pdf
All told, 25 projects (some facilities will have multiple liquefaction and purification trains) are planned, representing approximately 36 Bcf/day of export capacity and exceeding $50 billion in potential capital commitments. A look at the Department of Energy’s (DOE) applications for export lists 51 applications, 42 of which are for the Gulf Coast.
Many of these projects are far from being built and many still await approvals from FERC and the DOE. That said, the abundance of shale gas in the U. S. and the ability to tie the long term gas contracts to Henry Hub pricing make these facilities some of the most competitive in the world market. Interest from Asian and European buyers is very high and can be seen in the commitments being made to these facilities by BG (British Gas, now in merger with Shell), Osaka Gas (Japan), Chubu Electric (Japan), Pertamina (Indonesia), Endesa (Spain), Iberdrola (Spain), Gas Natural Fenosa (Spain), Woodside (Australia), Petronet (India), Mitsubishi (Japan), Mitsui & Co. (Japan), GDF Suez (France), EDF (UK), and EDP (Portugal).
There are currently 34 LNG liquifaction plants internationally with 16 under construction. With the addition of the potential U.S. and Canadian facilities that number could almost double in 10 – 20 years. While much risk and uncertainty surrounds these projects they are yet another offspring of the shale revolution.
Based on demand, LNG production is expected to double in the next 20 years.
Japan and South Korea accounted for 75% of 2014 demand but China, India, and other Asian economies (Thailand, Singapore, the Philippines, Vietnam) are expected to have greater growth in the years ahead. Asia will remain the primary demand center as exemplified by their 2014 imports of 180 MTPA (23 Bcf/d) which is 6 times greater than the nearest competitor, Europe.
LNG accounts for only 10% of Europe gas demand due Russia’s Gazsprom which pipes in 14.3 Bcf/d (> one-third of the market). However, Western European countries that were not part of the old Soviet bloc, imported more gas from Norway in the 1Q 2015 for only the 2nd time in recent history (think Ukraine conflict). Since European gas production, primarily from Norway and the Netherlands, is forecast to decline significantly in the next 20 years LNG demand is expected to double by 2025 and triple by 2035. That fact bodes well for U. S. exporters (with contracts tied to Henry Hub) who will be able to compete more effectively in the more liquid European spot market.
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