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Last Updated: March 22, 2017
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Last Week in World Oil:

Prices

  • Despite a midweek bounce in prices last week on an unexpected fall in US stockpiles, oil prices started the week on a weaker note. WTI is now at US$48/b and Brent at US$51/b, as disrupted Libyan port shipments resume after insurgent activity and US data continues to show rising drilling.

Upstream & Midstream

  • BP and Ineos are in talks over the Forties pipeline. Comprising pipelines that transports over 450 kb/d of oil, Forties is the largest constituent of Dated Brent, the international crude benchmark. After selling its stake in the Central Area Transmission System for £324 million in 2015, BP is now mulling selling some or the entirety of Forties, which it owns outright, to pare down debt acquired over the Deepwater Horizon spill. BP has already sold to Forties field to Apache and the Grangemouth refinery to Ineos over the last decade, so a sale would continue the ongoing trend of BP withdrawing from its aging North Sea assets.
  • Production at Total’s Moho Nord site in the Republic of Congo has started up, after repeated delays. The field has estimated output of some 100 kb/d per day, shared between operator Total (53%), Chevron (31.5%) and Societe Nationale des Petroles du Congo (15%).
  • The US active rig count is now at an 18-month high, with 14 new oil rigs, 6 new gas rigs and 1 miscellaneous site starting up last week.

Downstream

  • Russian will be increasing their production of high-octane gasoline this year, when five refineries complete upgrades that could add up to 4.5 million tons of production capacity. Given that domestic consumption is relatively flat, the gasoline will likely be exported – probably to Central Asia and East Europe – up existing imports of some 3.4 million tons.
  • After suddenly halting oil product shipments to Egypt last October, Saudi Aramco has announced that it will resume the agreed shipments of 700,000 tons of oil products per month, signalling a thawing of relations between both countries after Egypt voted in favour of a UN resolution on Syria, which was opposed by Saudi Arabia.
  • ExxonMobil is reportedly selling half of its 2,500 strong fuel station network in Italy. With an estimated price of €500 million, the company joins Shell and Total in exiting the oversupplied Italian market. Private equity firm Apollo is the frontrunner to acquire the Esso-branded stations, possibly combining it with Total’s stations for rationalisation.

Natural Gas and LNG

  • Shell’s divestment drive continues and the latest target for sale appears to be the gas-rich Haynesville Shale portfolio, acquired during its purchase of the BG Group and now ironically identified for sale to pay for that buy.

Corporate

  • The John Wood Group will acquire engineering service provider Amec Foster Wheeler for £2.23 billion (US$2.7 billion), continuing a trend of service providers merging to combat the weak environment in the industry, including GE’s merger with Baker Hughes in October 2016.


Last Week in Asian Oil:

Upstream & Midstream

  • China’s YTD crude oil production slipped by 8% y-o-y to 31.44 million tons as upstream companies scale back operations at aging fields over rising costs, preferring instead to import more crude oil. Crude oil imports over January and February 2017 was up 12.5% while crude processing volumes were up by 4.3%, as both the Chinese majors and independent teapot refiners raise production runs.
  • Iran is now India’s second-largest supplier of crude, leapfrogging India in February. Iranian volumes rose by nearly 17%, as OPEC producers Saudi Arabia and Iraq sent less crude to India as part of the organisation’s production cuts, returning Iran to the position it occupied pre-sanctions.

Downstream & Shipping

  • Sinopec may be acquiring its first major African downstream assets, as it nears buying Chevron’s South African oil assets for US$1 billion. The assets include fuel retail and storage terminals, as well as the 110kb/d Cape Town refinery. Sinopec was one of the few parties that expressed interest in keeping the refinery running instead of converting it into a storage terminal, though talks on that with the government may still fail.
  • BP has sold half of its 20% stake in the New Zealand Refining Company for US$56.2 million. Part of its global portfolio review, the buyer was not identified and BP will be continuing its processing arrangement with New Zealand Refining, along with ExxonMobil and Z Energy.

Natural Gas & LNG

  • The beleaguered US$37 billion Ichthys LNG project in Australia, led by Japan’s Inpex, has hit another snag. More than 600 workers of a subcontractor were terminated over a contractual dispute regarding the building of LNG storage tanks near Darwin. Despite this, Inpex states it is sticking to the massive project’s expected start up of Q32017.
  • Total is seeking up to a 50% stake in the US$4 billion South Pars gas field project in Iran, after becoming the first Western oil major to sign preliminary energy pacts with Iran as it came in from the cold. If finalised, Total would be the operator of South Pars with 50.1%, with China’s CNPC (30%) and Iran’s Petropars (19.9%) being the other shareholders.

Corporate

  • Commodities trader Cargill is selling its petroleum business to Australian investment bank Macquarie Group, as it admits defeat after the prolonged slump in oil prices saw Cargill struggling. Macquarie has an existing global oil business and the Cargill deal will add operations in Geneva and Minneapolis, Minnesota to its portfolio.
  • Singapore’s offshore industry was hit with another blow last week as oilfield services firm Ezra Holdings filed for Chapter 11 bankruptcy in the US. The company said it had been trying to restructure over the last year in the face of challenging conditions, and it is joined by Emas Chiyoda Subsea, an affiliate that has also filed for bankruptcy for which Ezra has provided guarantees on nearly US$900 million in loans and liabilities. In another sign of the tough environment in Singapore, Keppel Offshore and Marine CEO Chow Yew Yuen announced a surprise step-down last week, with Chris Ong appointed as his acting replacement.

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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