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Market Watch

Headline crude prices for the week beginning 29 January 2017 – Brent: US$69/b; WTI: US$65/b

  • Oil remains near its recent highs, correcting slightly at the start of this week with a rebound in the dollar and positive US crude output data.
  • The US dollar has been sliding since December, boosting prices – since crude oil is priced in US$. With the US seemingly signalling that a weak dollar might be beneficial, this could further fuel the crude rally.
  • Solidarity within OPEC and its NOPEC allies, led by Russia, is reassuring markets that the group will act beyond 2018 if necessary.
  • A tenth consecutive fall in weekly US crude inventories boosted prices last week, but consensus within the industry is that stockpiles will gain this week, while American output is expected to hit 10 mmb/d ‘soon.’
  • However, US Energy Secretary Rick Perry stood with energy ministers from Russia and Saudi Arabia at Davos last week, stating that he believes the US will not become a ‘spoiler’ for oil markets as new production gets absorbed by global demand, which has returned to healthy growth.
  • Hedge funds have also reportedly bet big on Brent and WTI continuing to rise, as the price future curve is moving in backwardisation all the way through 2022, indicating either rising demand, tightening supply, or both.
  • Confidence has returned, as a poll by DNV GL shows that 63% of 813 industry executives were positive for 2018, with Europe showing the largest improvement (25% to 64%) and Asia at 57% (up from 30%).
  • The active US oil and gas rig count jumped by 11 last week, as the addition of 12 new oil rigs – particularly in the Permian, where the number grew by 18 – offset the loss of a single gas rig.
  • Crude price outlook: The week started with a small correction, but there is enough confidence to keep oil prices at recent levels. US data may temper rises, but Brent should remain within range of US$70/b and WTI at US$66/b.


Headlines of the week

Upstream

  • BP has announced two more new major finds in the UK North Sea; the Capercaillie and Achmelvich discoveries join 18 expected new North Sea startups this year, while boosting BP’s output to 200,000 barrels by 2020.
  • The first export cargo of 500,000 barrels out of the North Sea Catcher Area are been sold a premium to Brent, surprising analysts.
  • China’s CNOOC and Norway’s Petoro has relinquished their interest in the last remaining exploration licence in Iceland; with only a minor junior partner left, this is likely to end of Iceland’s dream of finding oil.
  • Eni has begun exploratory drilling in the Black Sea with Rosneft, but keeping an eye out that it does not circumvent US sanctions on Russia.
  • Russia has remained China’s top crude oil supplier for a 10th month in December 2017, capping off its second year ahead of Saudi Arabia. Russian exports to China hit 1.194 mmb/d over 2017.

Downstream

  • Gunvor has received provisional approval from The Netherlands to add a fuel upgrading unit at its 88 kb/d Rotterdam refinery to meet strict new emission standards for shipping fuels.
  • Russia’s Tatneft has started up a naphtha hydrotreater and isomerisation unit at its TANEKO refinery to improve gasoline quality and gasoil yield.
  • The UAE’s Mubadala Petroleum has announced plans to double the capacity of the Pak Arab refinery in Karachi, Pakistan to 200 kb/d.

Natural Gas/LNG

  • The first Russian LNG cargo has landed in the USA, with the Gaselys tanker dropping off Siberia-sourced LNG in Boston. A second shipment, also by France’s Engie, may be on its way, heading to Massachusetts.
  • Nigeria is seeking to amend its law on gas-flaring penalty, moving it from a charge to a fine, as the former enjoys a tax relief which potentially cost the government billions in gas flaring penalty revenue.
  • Hess Midstream Partners and Targa Resources have formed a joint venture to build a 300 mscf/d dry gas processing plant in Little Missouri, North Dakota to capture gas that is currently being flared in the Bakken.
  • Bangladesh and Indonesia have signed an agreement on LNG imports, as the South Asian country seeks to plug its domestic shortage of natural gas. Bangladesh has several FSRU projects in the pipeline, signing its first ever LNG import deal with Qatar last September.
  • Mubadala Petroleum is aiming to finalise the FID on the Pegaga offshore gas condensate project in Malaysia within this quarter.
  • The government of Sarawak has acquired a 10% stake in the Bintulu LNG complex’s new Train 9, with Petronas acquiescing to the state’s demands.

Corporate

  • Preparing for the future, BP has invested US$5 million in US electric vehicle charging firm FreeWire and is also reportedly considering a US$1.8 billion bid for Italian solar firm Rete Rinnovabile.
  • Malaysia’s Sapura Energy – its largest oil and gas services company – is evaluating a potential public listing of its E&P business on the KLSE.

Thailand’s PTTEP reported a 60% jump in full year 2017 net profits, up to US$594 million from US$ US$372 million, while keeping an eye out to acquire oil and gas assets in Southeast Asia and the Middle East.

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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