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Last Updated: November 16, 2017
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Last week in the world oil:

Prices

  • Crude prices are down slightly as American drillers predictably added rigs to capitalise on the recent high prices. Brent is trading at US$63/b and WTI at US$56/b, still in the upper range of recent price trends.

Upstream

  • Ghana has begun talks with ExxonMobil that could see the US supermajor begin exploring the offshore Deepwater Cape Three Point (DCTP) region. Ghana is bypassing traditional auctions for this, given its peculiar nature of the field, opting to negotiate directly with the experienced ExxonMobil.
  • Also in Ghana, Kosmos Energy will resume development drilling in the TEN deepwater oil and gas project in early 2018, delayed slightly from end-2017. The move comes as the International Tribunal for the Law of the Sea redrew ocean boundaries to favour Ghana over the Ivory Coast, paving the way for work to begin in the disputed area. TEN is led by Kosmos Energy, with Tullow Oil, Anadarko, PetroSA and GNPC.
  • Gambia is moving ahead with plans to market the two offshore oil blocks revoked from Norwegian-based African Petroleum earlier this year. The blocks A1 and A4 are estimated to contain up to 3 billion barrels.
  • Crude output in Venezuela is expected to sink to 1.84 mmb/d next year, the lowest in almost three decades as a cash crunch and mounting debts by PDVSA pile up. Venezuelan rig counts hit a 14-year low in October.
  • Shell shut down its offshore Enchilada platform in the US Gulf of Mexico after a fire broke out. Nearby infrastructure at the Salsa and Auger platforms, a gas export pipeline and associated fields were also shut. Impact should be minimal and output could restart within the month.
  • As Tullow Oil prepares to develop the Turkana oil fields, Kenya’s government is attempting to placate the tribesmen in the area, proposing to give 30% of the prospective oil avenue to the local community there in a bill. Full production of the 750 million barrel asset will begin in 2021.
  • American drillers added 9 new drilling rigs last week – all oil – responding to the recent strength in crude prices.

Downstream & Midstream

  • Egyptian Refining Co’s new US$3.7 billion refinery in Cairo is expecting completion by June 2018 with operations beginning in September. All product from the public-private 100 kb/d refinery will be sold to EGPC.

Natural Gas and LNG

  • Algeria’s Sonatrach is pumping in US$2 billion into the Hassi Rmel gas field to keep production there stable. The goal of the investment is to maintain output levels of 190 mcm/d over the next 10 years at the JGC-led field that represents 60% of Algeria’s gas production.
  • Egypt will be awarding its recent 12-cargo LNG tender to Spain’s Gas Natural Fenosa, Trafigura, Vitol and Glencore, as its goal of reducing LNG imports even further continues with growing domestic gas output.

Corporate

  • France’s Total has acquired the upstream LNG assets of French power and gas utility Engie for US$1.5 billion. This includes stakes in the Cameron LNG project in the US, a tanker fleet and existing sales contracts. Total will now be the second-largest LNG player in the world, behind Shell.

Last week in Asian oil

Upstream

  • A blast at Bahrain’s oil pipeline running through Buri has been blamed on Iran, with Iran vehemently denying involvement. The fire rattled Asian crude prices, already nervous after recent events in Saudi Arabia.
  • Production at the offshore Hail oilfield in the UAE has begun. Led by ADOC, Cepsa and Cosmo Oil, Hail is the fourth field to start production in the ADOC concession, joining the aging Mubarraz, Umm Al-Anbar and Neewat Al-Ghalan finds in the shallow waters off Abu Dhabi.

Downstream

  • Saudi Aramco will be pushing back planned maintenance at the Ras Tanura refinery’s condensate splitter to the end of November. The month-long shutdown at Saudi Arabia’s largest refinery will be shut until the end of December, with minimal impact on operations.
  • South Korea refiners are preparing to spend over US$5 billion to upgrade their plants in an attempt to benefit from tighter shipping emission standards entering force in 2020. The IMO’s decision will bring sulphur caps down from 35,000 ppm to 5,000 ppm, attempting to establish itself as a new bunkering force in Asia. SK Energy is adding a US$900 million desulphurisation unit, while Hyundai Oilbank will begin expanding its heavy oil upgrading capacity next year and S-Oil starts on its US$4.3 billion residue fuel oil upgrading unit/olefins complex in 1H18.
  • Rosneft and its new major investor, CEFC China Energy, are looking at the possibility of building a new petrochemical complex in Yangpu, Hainan. Capacity and timeline are unknown, with condensate and LPG feedstock presumably sourced from Rosneft.

Natural Gas & LNG

  • PetroChina will be expanding LNG storage capacity at the Caofeidian import facility in northern China to meet soaring domestic demand. Together with Beijing Enterprises Group, PetroChina will be adding two 160,000 cubic metre tanks at Caofeidian, doubling storage capacity to 1.28 million cubic metres, which will become PetroChina’s largest gas storage space, eclipsing two terminals in Dalian and Rudong in Jiangsu.
  • Japan’s Inpex announced that production at the offshore Ichthys LNG project in Australia will begin in March 2018, the fifth of Australia’s mega LNG export facilities to start up.

Corporate

  • Saudi Aramco will be boosting its capital expenditure budget by some 10% next year, as it prepares to restructure ahead of its planned IPO. This would take capital spending above US$100 billion, up from the US$93 billion allocated for 2017, to be primarily focused on domestic projects.
  • Petronas may be forced to exit Myanmar, as members of the Malaysian parliament have demanded that the state oil firm depart from upstream there in protest of the recent, ongoing violence against the Rohingya Muslim community. Its assets in Myanmar are predominantly gas-based, including a pipeline to ships gas to Thailand.

Saudi energy services company Arkad is forming a joint venture with Switzerland-s ABB to build a North Africa and Gulf-focused business. The focus of the new company will be on Algeria, Kuwait and the UAE.

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Libya & OPEC’s Quota

The constant domestic fighting in Libya – a civil war, to call a spade a spade, has taken a toll on the once-prolific oil production in the North African country. After nearly a decade of turmoil, it appears now that the violent clash between the UN-recognised government in Tripoli and the upstart insurgent Libyan National Army (LNA) forces could be ameliorating into something less destructive with the announcement of a pact between the two sides that would to some normalisation of oil production and exports.

A quick recap. Since the 2011 uprising that ended the rule of dictator Muammar Gaddafi, Libya has been in a state of perpetual turmoil. Led by General Khalifa Haftar and the remnants of loyalists that fought under Gaddafi’s full-green flag, the Libyan National Army stands in direct opposition to the UN-backed Government of National Accord (GNA) that was formed in 2015. Caught between the two sides are the Libyan people and Libya’s oilfields. Access to key oilfields and key port facilities has changed hands constantly over the past few years, resulting in a start-stop rhythm that has sapped productivity and, more than once, forced Libya’s National Oil Corporation (NOC) to issue force majeure on its exports. Libya’s largest producing field, El Sharara, has had to stop production because of Haftar’s militia aggression no fewer than four times in the past four years. At one point, all seven of Libya’s oil ports – including Zawiyah (350 kb/d), Es Sider (360 kb/d) and Ras Lanuf (230 kb/d) were blockaded as pipelines ran dry. For a country that used to produce an average of 1.2 mmb/d of crude oil, currently output stands at only 80,000 b/d and exports considerably less. Gaddafi might have been an abhorrent strongman, but political stability can have its pros.

This mutually-destructive impasse, economically, at least might be lifted, at least partially, if the GNA and LNA follow through with their agreement to let Libyan oil flow again. The deal, brokered in Moscow between the warlord Haftar and Vice President of the Libyan Presidential Council Ahmed Maiteeq calls for the ‘unrestrained’ resumption of crude oil production that has been at a near standstill since January 2020. The caveat because there always is one, is that Haftar demanded that oil revenues be ‘distributed fairly’ in order to lift the blockade he has initiated across most of the country’s upstream infrastructure.

Shortly after the announcement of the deal, the NOC announced that it would kick off restarting oil production and exports, lifting an 8-month force majeure situation, but only at ‘secure terminals and facilities’. ‘Secure’ in this cases means facilities and fields where NOC has full control, but will exclude areas and assets that the LNA rebels still have control. That’s a significant limitation, since the LNA, which includes support from local tribal groups and Russian mercenaries still controls key oilfields and terminals. But it is also a softening from the NOC, which had previously stated that it would only return to operations when all rebels had left all facilities, citing safety of its staff.

If the deal moves forward, it would certainly be an improvement to the major economic crisis faced by Libya, where cash flow has dried up and basic utilities face severe cutbacks. But it is still an ‘if’. Many within the GNA sphere are critical of the deal struck by Maiteeq, claiming that it did not involve the consultation or input of his allies. The current GNA leader, Prime Minister Fayyaz al Sarraj is also stepping down at the end of October, ushering in another political sea change that could affect the deal. Haftar is a mercurial beast, so predictions are difficult, but what is certain is that depriving a country of its chief moneymaker is a recipe for disaster on all sides. Which is why the deal will probably go ahead.

Which is bad news for the OPEC+ club. Because of its precarious situation, Libya has been exempt for the current OPEC+ supply deal. Even the best case scenarios within OPEC+ had factored out Libya, given the severe uncertainty of the situation there. But if the deal goes through and holds, it could potentially add a significant amount of restored crude supply to global markets at a time when OPEC+ itself is struggling to manage the quotas within its own, from recalcitrant members like Iraq to surprising flouters like the UAE.

Mathematically at least, the ceiling for restored Libyan production is likely in the 300-400,000 b/d range, given that Haftar is still in control of the main fields and ports. That does not seem like much, but it will give cause for dissent within OPEC on the exemption of Libya from the supply deal. Libya will resist being roped into the supply deal, and it has justification to do so. But freeing those Libyan volumes into a world market that is already suffering from oversupply and weak prices will be undermining in nature. The equation has changed, and the Libyan situation can no longer be taken for granted.

Market Outlook:

  •  Crude price trading range: Brent – US$41-43/b, WTI – US$39-41/b
  • While a resurgence in Covid-19 cases globally is undermining faith that the ongoing oil demand recovery will continue unabated, crude markets have been buoyed by a show of force by Saudi Arabia and US supply disruptions from Tropical Storm Sally
  • In a week when Iraq’s OPEC+ commitments seem even more distant with signs of its crude exports rising and key Saudi ally the UAE admitting it had ‘pumped too much recently’, the Saudi Energy Minister issued a force condemnation on breaking quotas
  • On the demand side, the IEA revised its forecast for oil demand in 2020 to an annual decline of 8.4 mmb/d, up from 8.1 mmb/d in August, citing Covid resurgences
  • In a possible preview of the future, BP issued a report stating that the ‘relentless growth of oil demand is over’, offering its own vision of future energy requirements that splits the oil world into the pro-clean lobby led by Europeans and the prevailing oil/gas orthodoxy that remains in place across North America and the rest of the world

END OF ARTICLE

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September, 22 2020
Average U.S. construction costs for solar and wind generation continue to fall

According to 2018 data from the U.S. Energy Information Administration (EIA) for newly constructed utility-scale electric generators in the United States, annual capacity-weighted average construction costs for solar photovoltaic systems and onshore wind turbines have continued to decrease. Natural gas generator costs also decreased slightly in 2018.

From 2013 to 2018, costs for solar fell 50%, costs for wind fell 27%, and costs for natural gas fell 13%. Together, these three generation technologies accounted for more than 98% of total capacity added to the electricity grid in the United States in 2018. Investment in U.S. electric-generating capacity in 2018 increased by 9.3% from 2017, driven by natural gas capacity additions.

Solar
The average construction cost for solar photovoltaic generators is higher than wind and natural gas generators on a dollar-per-kilowatt basis, although the gap is narrowing as the cost of solar falls rapidly. From 2017 to 2018, the average construction cost of solar in the United States fell 21% to $1,848 per kilowatt (kW). The decrease was driven by falling costs for crystalline silicon fixed-tilt panels, which were at their lowest average construction cost of $1,767 per kW in 2018.

Crystalline silicon fixed-tilt panels—which accounted for more than one-third of the solar capacity added in the United States in 2018, at 1.7 gigawatts (GW)—had the second-highest share of solar capacity additions by technology. Crystalline silicon axis-based tracking panels had the highest share, with 2.0 GW (41% of total solar capacity additions) of added generating capacity at an average cost of $1,834 per kW.

average construction costs for solar photovoltaic electricity generators

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

Wind
Total U.S. wind capacity additions increased 18% from 2017 to 2018 as the average construction cost for wind turbines dropped 16% to $1,382 per kW. All wind farm size classes had lower average construction costs in 2018. The largest decreases were at wind farms with 1 megawatt (MW) to 25 MW of capacity; construction costs at these farms decreased by 22.6% to $1,790 per kW.

average construction costs for wind farms

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

Natural gas
Compared with other generation technologies, natural gas technologies received the highest U.S. investment in 2018, accounting for 46% of total capacity additions for all energy sources. Growth in natural gas electric-generating capacity was led by significant additions in new capacity from combined-cycle facilities, which almost doubled the previous year’s additions for that technology. Combined-cycle technology construction costs dropped by 4% in 2018 to $858 per kW.

average construction costs for natural gas-fired electricity generators

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

September, 17 2020
Fossil fuels account for the largest share of U.S. energy production and consumption

Fossil fuels, or energy sources formed in the Earth’s crust from decayed organic material, including petroleum, natural gas, and coal, continue to account for the largest share of energy production and consumption in the United States. In 2019, 80% of domestic energy production was from fossil fuels, and 80% of domestic energy consumption originated from fossil fuels.

The U.S. Energy Information Administration (EIA) publishes the U.S. total energy flow diagram to visualize U.S. energy from primary energy supply (production and imports) to disposition (consumption, exports, and net stock additions). In this diagram, losses that take place when primary energy sources are converted into electricity are allocated proportionally to the end-use sectors. The result is a visualization that associates the primary energy consumed to generate electricity with the end-use sectors of the retail electricity sales customers, even though the amount of electric energy end users directly consumed was significantly less.

U.S. primary energy production by source

Source: U.S. Energy Information Administration, Monthly Energy Review

The share of U.S. total energy production from fossil fuels peaked in 1966 at 93%. Total fossil fuel production has continued to rise, but production has also risen for non-fossil fuel sources such as nuclear power and renewables. As a result, fossil fuels have accounted for about 80% of U.S. energy production in the past decade.

Since 2008, U.S. production of crude oil, dry natural gas, and natural gas plant liquids (NGPL) has increased by 15 quadrillion British thermal units (quads), 14 quads, and 4 quads, respectively. These increases have more than offset decreasing coal production, which has fallen 10 quads since its peak in 2008.

U.S. primary energy overview and net imports share of consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

In 2019, U.S. energy production exceeded energy consumption for the first time since 1957, and U.S. energy exports exceeded energy imports for the first time since 1952. U.S. energy net imports as a share of consumption peaked in 2005 at 30%. Although energy net imports fell below zero in 2019, many regions of the United States still import significant amounts of energy.

Most U.S. energy trade is from petroleum (crude oil and petroleum products), which accounted for 69% of energy exports and 86% of energy imports in 2019. Much of the imported crude oil is processed by U.S. refineries and is then exported as petroleum products. Petroleum products accounted for 42% of total U.S. energy exports in 2019.

U.S. primary energy consumption by source

Source: U.S. Energy Information Administration, Monthly Energy Review

The share of U.S. total energy consumption that originated from fossil fuels has fallen from its peak of 94% in 1966 to 80% in 2019. The total amount of fossil fuels consumed in the United States has also fallen from its peak of 86 quads in 2007. Since then, coal consumption has decreased by 11 quads. In 2019, renewable energy consumption in the United States surpassed coal consumption for the first time. The decrease in coal consumption, along with a 3-quad decrease in petroleum consumption, more than offset an 8-quad increase in natural gas consumption.

EIA previously published articles explaining the energy flows of petroleum, natural gas, coal, and electricity. More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

Principal contributor: Bill Sanchez

September, 15 2020