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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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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

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

Nord Stream 2: Democratic Ideals or Business Reality

It was an innocuous set of words published in a newspaper in Germany on Sunday. “I hope the Russian do not force us to change our position on Nord Stream 2”, the German Foreign Minister Heiko Maas was quoted as saying. A day after that, Angela Merkel also issued a single sentence: “The German Chancellor agrees with the Foreign Minister’s comments from the weekend.” Simple words with a bold message. And potentially devastating consequences.

The incident that hardened the hearts of Germany , which had become increasingly isolated over the issue of the Nord Stream 2 natural gas pipeline that connects Russia to Germany through the Baltic Sea, was the hospitalisation of Russian opposition leader Alexei Navalny. Airlifted to Berlin following a medically-induced coma, German doctors concluded that Navalny, who is no stranger to intimidation tactics by the Putin government, was the victim of the Novichok nerve agent. If that name sounds familiar, that’s because it made headlines in 2018 over the attempted assassination of former Russian spy Sergei Skripal and his daughter Yulia in Salisbury, UK. A lethal nerve agent developed in the 1970s in Soviet Russia, Novichok is among the deadliest poisons ever developed and is banned under the Organisation for the Prohibition of Chemical Weapons. The Kremlin, predictably, denies involvement in the alleged poisoning, dismissing the German allegations as untrue.

That this could be the straw that broke the Nord Stream 2 back is perhaps surprising. The Nord Stream 2 natural gas pipeline has survived many obstacles. Many, many obstacles. The sequel to the original 1,222km Nord Stream that was inaugurated in November 2011, Nord Stream 2 will add 1,230km more pipeline between Vyborg in Russia and Lubin in Germany, with nearly all of the entire 2,452km length already being laid. Championed by former German Chancellor Gerhard Schröder and inherited by Merkel, the Nord Stream pipelines were developed to meet Germany’s growing energy demand, as it moved away from burning coal and nuclear fission. However, it has attracted criticism from many quarters. From Germany’s neighbours including Poland, Denmark and Estonia concerned over the pipeline that passes through their waters. From the EU, concerned about making Germany too energy dependent from a ‘politically unreliable’ country. From the US, which has threatened and, indeed, imposed sanctions on companies involved in the project. Some would argue that the vociferous US involvement, championed by President Donald Trump is self-serving, meant to allow US energy exports to muscle in, but it still fits neatly into Germany’s Russian dependence issue.

Throughout all this drama, Angela Merkel has stood firm. She, and her centre-right party CDU, have supported Nord Stream somewhat unenthusiastically with the primary concerns being the business element. It will unravel Germany’s plans to become a natural gas hub, as it tries to drive an EU movement towards cleaner energy. Many of Germany’s largest companies,  include petrochemicals giant BASF and its energy arm Wintershall are also heavily invested in Nord Stream and the raw gas it will bring. It would also be a reputational risk to pull the plug on a project that is almost complete and set to be launched by the year’s end, and still leaves the critical question on how Germany will be able to address its energy deficit.

The business argument has overridden political concerns so far. But now a moral imperative has arisen through the attempted murder of Alexei Navalny, with his subsequent medical treatment in Berlin. This resonates in Germany particularly, since the country understands the historical consequences of authoritarian governments and the dangers it bring. The shifting of the political landscape, especially the rise of the Green Party has triggered a ferocious debate with high-ranking politicians from both the left and right calling for the project to be scrapped. Some are even arguing that Nord Stream 2 gas supply is no longer necessary, as the country’s energy requirements are now fundamentally shifting in a post-Covid 19 world.

If, and that is a very big if, the Nord Stream 2 is scrapped, that is at least US$9.4 billion down the drain and plenty more in collateral damage from peripheral activities. It will rock the boat when the usual Merkel instinct is to steady it. But the furore over an attempted assassination by one of the world’s deadliest methods no less, might be a stand that Germany is willing to take. After all, it knows first-hand the effects of an iron fist. Berlin has so far stood alone in advancing Nord Stream 2, even after the chorus of critics surrounding it grow louder and louder. If it were to kill the project, Germany could find plenty of supporters for that move and would be more than happy to offer themselves up as a role to scupper this ship. The options are varied, but one question remains that will influence the whole issue: how is Angela Merkel willing to go to take a stand over democratic ideals or business reality?

Market Outlook:

  • Crude price trading range: Brent – US$39-41/b, WTI – US$36-38/b
  • A second global acceleration in Covid-19 cases is hampering hopes that the worldwide economy will be able to return to normality by the year’s end, delaying the time it will take for crude demand to return to its pre-crisis level
  • With the summer driving season in the northern hemisphere coming to a close, US crude stockpiles are rising, driving down prices even though the US EIA raised its forecasts for 2020 to US$38.99 for WTI and US$41.90 for Brent
  • The downturn in prices was also driven by Saudi Arabia cutting its crude pricing for October sales by a larger-than-expected amount, especially for Asian shipments

END OF ARTICLE

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Saudi Aramco – Dividends over Diversification

It does not seem that long ago when Saudi Arabia’s crown jewel, Saudi Aramco was about to make a huge splash by listing (a tiny portion of itself) publicly for the first time. Although that was less than a year ago, many of the details then have now been glazed over. Over the final quarter of 2019, the IPO timeline was in considerable flux, reportedly because the Saudi Crown Prince was determined to engineer a US$2 trillion debut valuation. It did not. At least not immediately, starting at US$1.88 trillion before briefly hitting target after. Several months later, a global pandemic has significantly reduced that valuation. Not only that, Saudi Aramco no longer has claim to the title of the world’s most valued company. That belongs to Apple.

But that’s besides the point now. What matters is Aramco’s commitments in the lead-up to its valuation. In order to generate the maximum amount of interest, mainly from the ruling and connected Saudi families, Aramco promised to hand out over US$75 billion in annual dividends through 2025. Even in better times, that’s a huge promise. But now that the oil price situation has upended, it seems unsustainable.

For another company, public-listed or private, the solution would be simple. Scale back announced dividend payouts, or stop them completely. That’s what companies like Shell, BP and Total have done. In an economic crisis, most investors would understand. But what if the major shareholder is a government? Aramco is still 98% owned by the Saudi government, and the federal coffers, which run everything from the national airline to plans to open up for official tourism are dependent on the dividends that Aramco pays. Adjusting the dividend payouts is not an option, particularly since the government is already far from balancing its budget even with the current fiscal structure. The blurred line between Saudi Arabia and Saudi Aramco is a double-edged sword; and it is now a liability for a company that finds its hands shackled and its flexibility to manoeuvre cemented down due to its commitments.

This need to prioritise dividends means that Saudi Aramco has a reckoning to face. Its valuation and, indeed, business plan was driven by a diversification strategy that was meant to move Aramco from an upstream-focused titan to an integrated behemoth. Aramco had invested in key refining nodes throughout Asia and the world that ensure captive demand for its crude in key markets. It bought SABIC in a pricey deal that was part of a petrochemicals-heavy downstream dive. It set up an LNG trading desk in Singapore before it even produced a single drop of liquefied natural gas. With dry season in the oil and gas world setting in, some of these projects must now wither so that the rest of Saudi Aramco can survive.

A spate of cancellations and deferments have been announced. The planned US$20 billion crude-to-chemicals plan in Yanbu is likely to be cancelled outright. The decision to purchase 25% of Sempra Energy’s Port Arthur LNG project in Texas is being reviewed. A US$6.6 billion plan to add new petrochemicals capacity at the Motiva refinery on the US Gulf Coast is on pause. Downstream plans linked to greenfield refinery investments in Pakistan, India and China have been delayed. CEO Amin Nasser has slashed CAPEX for 2020 from US$40 billion to US$25 billion, and the March 2020 plans to boost crude output capacity within the Kingdom (to 13 mmb/d from a current 12 mmb/d) have been deferred by a year.

But, as dire as this sounds, this is more of a refocusing rather than a reckoning. There is a certain trend here, where outright cancellations are linked to eliminating risk of excess capacity, while delays are linked to new projects and expansions. In petrochemicals, for example, Aramco’s SABIC purchase means it already has a large surplus of production capacity. Adding to that right now, with the global economy expected to be weak for years, is not good business. But Aramco is also committed to expanding its natural gas/LNG offerings and securing long-term demand nodes through refining for its crude. It is just admitting that now is not the best time to focus on those.

It is then instructive to look at what projects have not been affected by the slash in funding. It remains in talks to acquire a stake in India’s Reliance and an integrated downstream site in China’s Zhoushan. The Yanbu plans are expected to be repackaged as incremental upgrades to existing sites, a move to focus on upgraded brownfield sites over building greenfield ones. And drilling still continues, with Aramco announcing the discovery of two new oil and gas assets near the Kingdom’s border with Iraq, with the Hadabat Al-Hajara and Abraq at-Tulul fields offering a mixture of light crude, condensates and natural gas to the market.

Saudi Aramco is not retreating because it wants to. It is retreating because it has to. All indications now appear to show that Aramco is committed to following the strategy roadmap it has outlined previously. At least in the future, Aramco will become more diversified and in line with industry expectations. The current dividend situation has made Aramco less nimble. Admitting its challenges maybe out of character for Saudi Aramco. But the one thing that all can admit right now is that a pause is necessary in order to figure out the best way forward.

Market Outlook:

  • Crude price trading range: Brent – US$41-43/b, WTI – US$38-40/b
  • Weak economic data – especially with major economies announcing the worst-ever GDP figures on record for Q2 2020 – have depressed crude prices, with fears that overall recovery will be a long and harsh road
  • The rampage of Hurricanes Laura and Marco took 82% of US Gulf oil production offline, but the temporary price boost from that has now tapered out as the weather patterns recede
  • However, there are indications that growth is outstripping expectations, especially in Asia, with IHS Markit reporting that global oil demand is now at 89% of pre-Covid in July levels, compared to 78% in April 2020
  • Baghdad is looking to mollify its fiercest critics within OPEC+, promising to implement extra cuts to meet its commitments but requesting an additional two months through November 2020 to resolve the matter

End of Article 

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In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

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As U.S. coal-fired capacity and utilization decline, operators consider seasonal operation

Coal-fired electricity generating capacity in the United States is retiring, as tighter air emission standards and decreased cost-competitiveness relative to other power resources make coal-fired power plants less economical. From 2011 to mid-2020, 95 gigawatts (GW) of coal capacity was closed or switched to another fuel and another 25 GW is slated to shut down by 2025, based on information power plant operators reported to the U.S. Energy Information Administration (EIA). The closures will decrease the capacity of the U.S. coal fleet to less than 200 GW, more than one-third lower than its peak of 314 GW in 2011. As the coal-fired fleet is retired and remaining plants are utilized less, plant owners are evaluating new operating models, such as seasonal operation.

Although the U.S. coal-fired power plant fleet is downsizing, coal-fired plants are still an important resource to meet electricity demand, especially during peak periods. This factor was evident during the heat wave that gripped most of the United States during July and August 2020. Data from EIA’s Hourly Electric Grid Monitor show that output from coal-fired generating plants reached an hourly dispatch of 161.5 GW on July 27, 2020. Of the electricity generated on July 27 in the Lower 48 states, 24% was coal-fired. Only natural gas-fired sources held a higher share at 45%.

daily range of hourly electricity generation from coal, Lower 48 states

Source: U.S. Energy Information Administration, Hourly Electric Grid Monitor

The coal power plant fleet is used much less during electricity’s shoulder months of spring (March, April, and May) and fall (September, October, and November). During the winter and summer months, the coal fleet operates at an average capacity factor, or utilization rate, of more than 60%. However, in the spring and fall, the average capacity factor has been less than 50%.

Seasonal differences in capacity factor have become more pronounced during the past two years, largely because coal has been displaced by cheaper generation from natural gas and renewable energy during the shoulder months. In April and May 2020, the coal fleet operated less than 30% of the time. As a result, coal plants sometimes assert that they are unable to operate for enough hours to produce enough annual revenue to cover costs.

U.S. coal-fired electricity generating fleet average monthly capacity factor

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

In an effort to improve the economics of coal plants, owners are evaluating plans to run plants on a seasonal basis, when electricity demand allows for steadier operation. Under these plans, coal plants would only operate during periods of higher electricity demand, from December to February (winter) and from June to August (summer). The expectation is that completely shutting down plants when electricity demand is low will limit financial losses.

So far in 2020, four large coal-fired plants announced plans to operate on a seasonal basis. Two of the plants, totaling 1,193 megawatts (MW), are in Minnesota. The other two are a 793 MW plant in Arizona and a 645 MW plant in Louisiana. The two units in Minnesota will run during the summer and winter. The plants in Arizona and Louisiana will only operate during summer because they are located in warmer climes.

Whether or not seasonal operation sufficiently improves the economics of coal plants remains to be seen. In 2018, owners of a plant in Wisconsin and a plant in Texas switched to seasonal operation. However, the practice lasted for less than a year because both facilities were completely shut down shortly thereafter.