Source: U.S. Energy Information Administration, International Energy Outlook 2017 Reference case
EIA’s International Energy Outlook 2017 (IEO2017) projects that among all regions of the world, the fastest growth in buildings energy consumption through 2040 will occur in India. In the IEO2017 Reference case, delivered energy consumption for residential and commercial buildings in India is expected to increase by an average of 2.7% per year between 2015 and 2040, more than twice the global average increase.
Most of this growth is the result of increased electricity and natural gas use (because of greater access to these energy sources) and the increased use of appliances and energy-using equipment. Despite the rapid growth in buildings energy consumption, the IEO2017 Reference case shows that, among the IEO2017 regions, India’s per capita buildings energy use through 2040 is the second lowest after Africa.
Source: U.S. Energy Information Administration, International Energy Outlook 2017 Reference case
Rapid economic growth, rising income, growing population, and urbanization are factors in the growth in India’s buildings energy consumption. Patterns of energy use vary between rural and urban populations. India has the world’s highest projected gross domestic product (GDP) growth rate among the IEO2017 regions, averaging 5.0% per year from 2015 to 2040.
During the projection period, household disposable income in India is expected to increase by an average of 4.2% per year, which is the second highest among IEO2017 regions after China. India is projected to account for about 19% of the increase in world population over the projection period, surpassing China as the world’s most populous country in 2023. The United Nations projects India’s population to continue to become more urbanized; about 45% of the Indian population will live in urban areas by 2040, an increase of nearly 12 percentage points from 2015.
Buildings energy consumption represented about 14% of total delivered energy consumption in India in 2015. Although EIA expects the rate of India’s commercial energy growth to be higher than its residential energy growth, the residential sector remains the greater consumer of buildings energy, representing more than 70% of the buildings total throughout the projection period.
In the IEO2017 Reference case, residential delivered energy consumption is projected to grow by an average of 2.4% per year from 2015 to 2040, the fastest growth rate among IEO regions. EIA expects household per capita disposable income to grow by an average of 3.2% per year as more people have access to electricity and the ownership of electricity-using appliances and equipment (particularly air conditioners) grows. As a result, EIA expects residential electricity consumption to increase nearly twice as fast as total residential sector energy use from 2015 to 2040. Electricity’s share rises from 46% of the energy delivered to India’s residences in 2015 to 68% in 2040.
India’s commercial sector accounted for nearly 69% of the country’s gross domestic product in 2015, and this share is expected to continue growing, leading to more energy demand in the commercial sector. EIA projects that total delivered commercial sector energy use in India will increase by an average of 3.4% per year—again, the fastest growth rate among IEO regions. India’s economic growth, rising income, and population growth are likely to increase the need for education, health care, leisure, recreation, and other services, which EIA expects will lead to an increase in demand for lighting, space cooling, and office equipment. In the IEO2017 Reference case, electricity and coal remain the most prominent fuels consumed in India’s commercial sector.
EIA projects the electricity share of India’s total commercial energy consumption to continue increasing, from 59% in 2015 to 65% in 2040, displacing some coal consumption. Buildings energy consumption in India is also affected by various energy efficiency programs such as the Standards and Labeling program and the Energy Conservation Building Codes.
More information about projected residential and commercial buildings energy consumption is available in EIA’s International Energy Outlook 2017.
Principal contributor: Behjat Hojjati
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Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.