India has been the world’s fourth-largest importer of liquefied natural gas (LNG) since 2011, gradually increasing LNG imports as the country’s domestic natural gas production declined and domestic consumption increased. India’s LNG import capacity more than doubled during the past 10 years, and the U.S. Energy Information Administration (EIA) expects it to increase by a third in the next 3 years as regasification facilities currently under construction come online. However, the construction of domestic pipelines to move LNG from the coastal import facilities to major demand centers further inland has experienced delays. Future growth in India’s LNG imports will depend on the timely completion of natural gas pipeline networks.
In recent years, growth in India’s LNG imports has been driven by declining domestic natural gas production and growing consumption, particularly in the industrial sector (where natural gas is used in the production of fertilizer) and City Gas Distribution network. India’s domestic production of natural gas, 70% of which is located offshore, has experienced a steady decline, from 4.4 billion cubic feet per day (Bcf/d) in 2012 to 2.9 Bcf/d in 2019, and it has limited potential for further growth.
India’s LNG imports have grown from 31% of the country’s natural gas supply in 2012 to more than 50% in 2019. India does not import natural gas by pipeline and has no plans to build natural gas pipelines through the deserts and mountains that form much of its northern borders.
Source: U.S. Energy Information Administration, based on India's Ministry of Petroleum and Natural Gas and Global Trade Tracker
Currently, natural gas constitutes a relatively small share (6%) of India’s total primary energy consumption. In 2019, the Indian government set a goal to increase the share of natural gas from 6.2% in 2018 to 15% by 2030. EIA expects future growth in consumption primarily in the industrial and power generation sectors.
Earlier this year, India commissioned its sixth LNG import terminal, bringing the total regasification capacity to 5.2 Bcf/d. Four more LNG import terminals—all but one of which are on the western coast (Arabian Sea)—are currently under construction and are expected to come online by 2023, adding 2.5 Bcf/d of LNG import capacity.
Source: U.S. Energy Information Administration, based on FG Energy and publicly available company and industry data
Future growth in India's LNG imports is contingent on connecting LNG regasification terminals on coasts to demand centers further inland via pipeline. Northwestern India has a highly developed natural gas infrastructure, and both Hazira and Dahej are the most highly utilized terminals in India (at 97% and 110%, respectively). However, the southern and eastern regions of the country lack pipelines to move natural gas from coastal LNG import terminals to major demand centers further inland.
The lack of pipeline infrastructure near LNG terminals is affecting both existing and planned LNG terminals. In southwestern India, LNG imports to the existing Kochi terminal are currently limited to local markets; pipelines expanding to nearby Mangalore are expected to come online in 2020 and Banagalore in 2022. Similarly, new pipelines are planned to connect the existing Ennore LNG terminal to areas beyond nearby Chennai. In northeastern India, new pipelines that are planned to come online within the next three years would connect the Dhamra LNG terminal currently under construction to nearby Kolkata as well as existing pipelines in northwest India.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL) annual LNG trade reports
Although India has expanded the number of countries it imports LNG from since 2016, Qatar remains the main LNG supplier to India because of a relatively short transportation distance: an LNG tanker can leave Qatar and reach India in three days. India’s LNG imports from the United States have grown to a total of 0.25 Bcf/d in 2019 and are expected to grow as new commercial contracts are considered between the two countries. In 2019, India ranked as the seventh-highest destination for U.S. LNG exports, receiving 5% of the U.S. total last year.
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In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.
In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.
Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.
We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.
Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.
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The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.
How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.
The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.
The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.
On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.
But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.
For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.
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