Nurliza Ibrahim

Marketing Specialist at NrgEdge
Last Updated: September 1, 2017
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Business Trends
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Last week in world oil:

Prices

  • Crude oil prices dipped – to US$46/b for WTI and US$51/b for Brent – as Hurricane Harvey reduced demand for crude by shutting down major refineries in Texas. At a premium of US$5/b, the Brent-WTI spread is the widest in two years, reflecting the impact of the hurricane. Gasoline prices jumped, as supplies are affected by Texan refinery and pipeline closures.

Upstream

  • France’s Total is now the largest upstream producer in the North Sea, overtaking Shell through its acquisition of Maersk Oil for US$7.45 billion. The sale came as part of Danish firm’s attempt to divest all its energy business to focus on its core business of shipping. Maersk Oil’s assets were confined to Norway and the UK North Sea, and it is now looking to sell off its drilling, tanker and supply service units separately. 
  • Petrobras expects oil production to begin at Brazil’s offshore Libra field in late September, delayed from July. Initial production will be 30,000 b/d, from an estimated recoverable volume of between 8 to 12 billion barrels. 
  • Despite recording healthy profits, BHP Billiton will be exiting the US shale oil and gas sector, which has been underperforming with shareholders calling for an exit. BHP Billiton bought into US shale in 2011 for US$20 billion during its ascendance, conceding now that they had paid too much and that it no longer fit ‘strategically’ to the company’s direction. 
  • Malaysia’s Petronas will be exiting the upstream business in Algeria, part of a portfolio rebalancing that has already seen it give up a pair of offshore blocks in Vietnam earlier this year. 
  • There was a net loss of six oil and gas rigs in the US last week, as the rebalancing of active drilling sites was exacerbated by the landing of Hurricane Harvey, which shut down onshore production activity.

Downstream & Midstream

  • PDVSA maintains that its lease to operate the Isla refinery in Curacao is still under negotiation, but has conceded that it is open to partnering with China’s Guangdong Zhenrong Energy to operate the complex. Curacao has signed an agreement with Zhenrong to operate the refinery, which requires substantial investment, with PDVSA’s lease ending in 2019.

Natural Gas and LNG

  • After scrapping its Canadian LNG terminal plans, Petronas is now reportedly mulling investing in a pipeline to monetise its Canadian assets. This would require in shift in focus from sending gas to Asia as LNG, to selling the gas by connecting to pipelines delivering gas to the US Gulf. 
  • As Equatorial Guinea prepares for the anticipated sanctioning of Fortuna floating LNG project off Bioko Island, the government has named Gunvor as preferred offtaker, in a deal covering 2.2 mtpa of LNG. Meanwhile, Ghana has signed an agreement to import LNG from Equatorial Guinea, as it struggles with adequate supplies for power production despite its own Jubilee oil-and-gas field being in production since 2010. 
  • Lithuania has received its first spot LNG cargo from Cheniere, joining a growing list of European nations embracing US LNG to reduce dependence on Russia piped natural gas. 


Last week in Asian oil

Upstream

  • Singapore’s KrisEnergy has inked an agreement to develop Cambodia’s first oil field. Oil was first discovered in Cambodia at Block A in 2004, but then-operator Chevron failed to reach a development agreement with the government. KrisEnergy bought over Chevron’s interest in 2014, and is aiming to produce oil from the Apsara field in 2019. The area is estimated to produce 30 million barrels over a nine-year period, and will be the culmination of a long, arduous and delayed process to produce Cambodia’s first oil. KrisEnergy owns a 95% stake in the Apsara field, with the remainder held by the Cambodian government.

Downstream & Midstream

  • Rosneft’s purchase of Indian refiner Essar Oil has been completed, giving the Russian major a foothold in Asia’s fastest-growing oil market after repeated attempts to invest in Asian downstream – notably in China and Indonesia – failed. The US$12.9 billion deal will see Rosneft and partners Trafigura and Russian fund UCP take a 98.26% stake in Essar Oil, with the remainder held by retail investors. Rosneft will now operate Essar’s 400 b/d refinery in Vadinar, as well as a port, a power plant and a network of 3,500 fuel stations. Rosneft expects to almost double the retail network size to some 6,000 sites, as well as significantly increase refining and petrochemical production capacity at Vadinar. 
  • The Saudi Aramco-PetroChina plan to see the Saudi Arabia state company invest in the latter’s 260 kb/d Anning refinery in Yunnan is expected to be completed by the end of 2017. This is part of a vanguard of Saudi Arabian investments in key downstream markets to ensure continued outlets for its crude, as well as diversify its business as it prepares for the world’s largest IPO. Aramco will be spending some US$1-1.5 billion on the refinery, which will also include access to PetroChina’s retail assets.

Natural Gas & LNG

  • South Korea’s S-Oil, the third largest Korean refinery, has signed a long-term LNG supply contract with Petronas. The 15-year contract will see Petronas deliver 700,000 tons of LNG from March 2018, with S-Oil electing to use the LNG as refinery fuel and petrochemical feedstock. This is part of a wider plan by S-Oil to upgrade the fuel oil that used to power its 669 kb/d refinery in Ulsan to more valuable middle distillates as the market for fuel oil shrinks, particularly in the bunker arena, along with an upgrade to increase polypropylene capacity by 405,000 tons. Long-term supply contracts like this are likely to be less common in the LNG arena as the rise of competition promotes shorter deals, meaning this is a decent coup by Petronas. 
  • PTT Global Chemical will be teaming up by Japan’s Sanyo Chemical Industries and Toyota Tshusho Corporation to build a US$900 million polyols facility. To be located in Thailand’s petrochemicals hub of Rayong, the plant will have an initial capacity of 130,000 tons of polyether polyols and 20,000 tons of polyurethane per year. Completion and operations are expected to begin in 2020. PTTGC will own 82.1% of the venture, with Sanyo Chemical and Toyota Tsusho holding 14.9% and 3%, respectively. 

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Wind has surpassed hydro as most-used renewable electricity generation source in U.S.

annual electricity generation from wind and hydroelectric sources

Source: U.S. Energy Information Administration, Electric Power Monthly

In 2019, U.S. annual wind generation exceeded hydroelectric generation for the first time, according to the U.S. Energy Information Administration’s Electric Power Monthly. Wind is now the top renewable source of electricity generation in the country, a position previously held by hydroelectricity.

Annual wind generation totaled 300 million megawatthours (MWh) in 2019, exceeding hydroelectric generation by 26 million MWh. Wind generation has increased steadily during the past decade, in part, because the Production Tax Credit (PTC), which drove wind capacity additions, was extended. Annual hydroelectric generation has fluctuated between 250 million MWh and 320 million MWh in the past decade, reflecting a stable capacity base and variable annual precipitation.

U.S. electricity generation from hydroelectric and wind

Source: U.S. Energy Information Administration, Electric Power Monthly

Annual changes in hydroelectric generation are primarily the result of variations in annual precipitation patterns and water runoff. Although weather patterns also affect wind generation in different regions, capacity growth has been the predominant driver of annual changes in wind generation.

Both hydroelectric and wind generation follow seasonal patterns. Hydroelectric generation is typically greatest in the spring when precipitation and melting snowpack increase water runoff. Seasonal patterns in wind generation vary across the country, but wind generation is usually greatest in the spring and fall.

operating capacity of hydroelectric and wind generators

Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory

Wind capacity additions tend to come online during the fourth quarter of the year, most likely because of tax benefits. Wind capacity additions totaled 10 gigawatts in 2019 (3.8 GW installed in the fourth quarter), making 2019 the second-largest year for wind capacity additions, second only to 2012.

As of the end of 2019, the United States had 103 GW of wind capacity, nearly all of which (77%) were installed in the past decade. The United States has 80 GW of hydroelectric capacity, most of which has been operating for several decades. Only 2 GW of hydroelectric capacity has been added in the past decade, and some of those additions involved converting previously nonpowered dams.

Although total installed wind capacity surpassed total installed hydroelectric capacity in 2016, it wasn’t until 2019 that wind generation surpassed hydroelectric generation. The average annual capacity factors for the hydroelectric fleet between 2009 and 2019 ranged from 35% to 43%. The average annual capacity factors for the U.S. wind fleet were lower, ranging from 28% to 35%. Capacity factors are the ratio of the electrical energy produced by a generating unit for a specified period of time to the electrical energy that could have been produced at continuous full power operation during the same period.

hydroelectric and wind capacity factors

Source: U.S. Energy Information Administration, Electric Power Monthly

February, 28 2020
EIA forecasts natural gas inventories will reach record levels later this year

In the U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO), EIA forecasts that the Lower 48 states’ working natural gas in storage will end the 2019–20 winter heating season (November 1–March 31) at 1,935 billion cubic feet (Bcf), with 12% more inventory than the previous five-year average. This increase is the result of mild winter temperatures and continuing strong production. EIA forecasts that net injections during the refill season (April 1–October 31) will bring the total working gas in storage to 4,029 Bcf, which, if realized, would be the largest monthly inventory level on record.

Mild winter temperatures for the current winter have put downward pressure on natural gas prices and led to smaller withdrawals from natural gas into storage. Year-over-year growth in dry natural gas production and natural gas exports—especially liquefied natural gas (LNG)—throughout 2019 also affected natural gas storage levels. On October 11, 2019, the total natural gas in storage surpassed the previous five-year average—an indicator of typical storage levels—for the first time since mid-2017.

lower 48 states working natural gas in storage

Source: U.S. Energy Information Administration, Natural Gas Monthly, Weekly Natural Gas Storage Report, and Short-Term Energy Outlook

The total natural gas in storage at the start of this heating season was 3,725 Bcf on October 31, 2019. EIA expects withdrawals from working natural gas storage to total 1,790 Bcf at the end of March 2020. If realized, this would be the least natural gas withdrawn during a heating season since the winter of 2015–16, when temperatures were also mild.

Injections into and withdrawals from natural gas storage balance seasonal and other fluctuations in consumption. Natural gas demand is greatest in the winter months, when residential and commercial demand for natural gas for space heating increases. Natural gas consumption in the power sector is greatest in summer months, when overall electricity demand is relatively high because of air conditioning.

monthly U.S. natural gas supply and disposition

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

In the latest STEO, EIA expects the total working natural gas in storage will exceed the previous five-year average for the remainder of 2020, despite declines in dry natural gas production, increases in natural gas consumption in the electric power sector, and increases in natural gas exports. EIA expects monthly natural gas production to decline from last year’s record levels in 2020 as lower natural gas prices reduce incentives for natural gas-directed drilling and as lower crude oil prices reduce incentives for oil-directed drilling and associated gas production.

February, 25 2020
The World’s Largest Natural Gas Discovery Since 2005

At the start of February, a major new find was jointly announced by the two largest emirates within the UAE: the oil-rich Abu Dhabi and the ambitious Dubai. Between them, they literally made the world’s largest natural gas discovery since 2005. Located at the border between the two sheikdoms, the Jebel Ali field is estimated to contain some 80 trillion scf of natural gas, the largest global find since the Galkynysh field in Turkmenistan.

Stretching over 5,000 square km, an exploration campaign by Abu Dhabi involving over 10 wells confirmed the enormous discovery in early January 2020. The shallow nature of the onshore reserves should make it easier to extract gas at lower costs, hastening the time-to-market. At current estimated figures, Jebel Ali would be the fourth-largest gas field in the Middle East, behind Qatar’s North Field, Iran’s South Pars and Abu Dhabi’s own Bab field.

The politics of the UAE can be complicated; each emirate is essentially self-governing with federal oversight, which is dominated by Abu Dhabi and Dubai (which always hold the President and Prime Minister roles, according to convention). This essentially means that each emirate has grew quite independently. Fujairah, for example, developed into a bunkering port, while Sharjah went into industry and manufacturing. Dubai is globally famous for its titanic real estate projects, pursued finance, services and media, while Abu Dhabi, the largest and most blessed of all with hydrocarbon resources, turned into an energy powerhouse. Oil & gas wealth in the UAE is mainly in Abu Dhabi; so while the Jebel Ali discovery is a welcome addition for Abu Dhabi, it is a game changer for Dubai, which imports most of its energy needs.

Speculation has raised that possibility that the Jebel Ali field could vault the UAE into gas self-sufficiency, because even Abu Dhabi imports gas. The UAE has a stated goal to be gas independent by 2030. On paper, that’s possible. Abu Dhabi’s ADNOC has agreed to develop the field with Dubai’s gas supplier, the Dubai Supply Authority (DUSUP), with the entire supply will be channel to DUSUP for use in Dubai. Jebel Ali could begin producing gas by 2023, and will likely be distributed domestically through pipeline. The enormous reserves could supply the entire UAE’s gas demand for nearly 30 years, assuming optimal recovery conditions. However, in practice, self-sufficiency might take longer to achieve.

Dubai and indeed, Abu Dhabi are currently reliant on Qatar for their gas supply. An existing sales agreement that expires in 2032 sees Qatar pipe 2 bcf/d of gas to the UAE through Abu Dhabi. The problem is that these neighbours are erstwhile friends. A division in the Middle East between the pro-Saudi Arabia and pro-Iran blocs has caused a rift. Led by Saudi Arabia, several Persian Gulf states  including the UAE implemented a diplomatic and trade blockade on Qatar, isolating it. The blockade, slightly weakened, still continues today. Even now, planes flying into Qatar have to make strange manoeuvres when approaching to avoid encroaching on Saudi and UAE airspace. However, the gas supply arrangement remains in place.

And this is where the Jebel Ali discovery could come in handy. Qatar is already on track to be self-sufficient in gas terms by 2025, but will probably honour the Qatar deal until expiration. Dubai has been increasingly reliant on LNG  through an FSRU for power generation, but has attempted over the years to kick-start a number of coal or solar-power projects. Jebel Ali won’t kick the addiction, but it could definitely reduce Dubai’s reliance on Qatari gas.

Jebel Ali wasn’t the only recent gas discovery made in the UAE. Further north, the Sharjah National Oil Corp and Italy’s Eni announced a new onshore gas and condensate discovery. Though tiny in comparison to Jebel Ali, some 50 mscf/d of lean gas and condensate. The cumulative effects of these discoveries could make gas self-sufficiency a reality sooner. At this point, the UAE consumes some 7.4 bcf gas per day, while marketed production is some 6.2 bcf/d. An ambitious plan to develop Abu Dhabi’s large gas fields was the rationale behind naming the 2030 self-sufficiency deadline. With the discovery of Jebel Ali, that can now be brought forward by a couple of years at least. And there might even be some left over to be exported as LNG

The UAE Major Gas Projects:

  • Estimated reserves: 273 tcf of conventional gas, 160 tcf of unconventional gas (Abu Dhabi)
  • Ghasha ultra-sour gas field (Abu Dhabi) – 1.5 bcf, by 2025
  • Shah sour gas field (Abu Dhabi) – 1.5 bcf/d

February, 23 2020