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Last Updated: June 14, 2017
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Last week in the world oil:

Prices

  • Oil prices remain weak, but edged up at the start of the week on news that US inventories had declined and that Saudi Arabia would limit crude sales to Asia in July and slash shipments to the US. However, simmering geopolitical tensions in the Arabian Gulf and increased US drilling activity is likely to keep a lid on prices below US$50/b for a while.

Upstream & Midstream

  • Shell has lifted its declared force majeure on Forcados crude exports, bringing all of Nigeria’s oil export facilities online for the first time in 16 months, after local militants disrupted operations through a sustained series of sabotage. With Nigeria exempt from the OPEC supply cuts, it can now raise its production back to expected levels of 1.8 mmbpd.
  • After previous talks with the South Sudan government collapsed, France’s Total says that the country has reapproached the French major to resume talks on developing the B1 and B2 oil blocks. Tullow Oil is also involved in the negotiations as South Sudan seeks foreign investment to unlock its hydrocarbon potential. B1 and B2 are part of the three blocks that make up the former Block B, the largest untapped oil deposit in South Sudan and central to the government’s plans to raise production from 130 kb/d to 200 kb/d by end-2017 and 300 kb/d by end-2018.
  • Commercial production from Eni’s offshore Sankofa field in Ghana will start in July, three months ahead of schedule with production of 45 kb/d. This is Phase 1 of the US$7.9 billion Offshore Cape Three Points project, which includes expected 180 mcf/d output at the Gye Nyame gas reserve.
  • Libya’s major Sharara field has reopened and should resume normal production levels of 270 kb/d within the week after a short workers’ strike over medical treatment coverage for employees.
  • Total operational oil rigs in the USA reached 741 last week, adding 8 new units. Along with 3 new gas rigs, that brings the American total to 927.

Downstream

  • Utilisation rates at Venezuela’s 187 kb/d Puerto la Cruz refinery has dropped down to 16%, as the Mesa 30 crude it depends on is redirected to Cuba and Curacao. Mesa 30 is a superlight crude used to dilute heavy Orinoco oil, but also prized by PDVSA’s foreign clients. Cuba, in particular, has taken up to 1.4 mmbpd of Mesa 30 since March, providing valuable foreign currency but exacerbating Venezuela’s refining crisis.

Natural Gas and LNG

  • While the gas world focuses on selling LNG to Asia, France’s Total is also looking at alternatives to grow its gas business by investing directly in gas-consuming industries. It has identified Morocco and South Africa as key countries to invest in gas and power projects, which will support an LNG portfolio that is expected to double to 15 million tons by 2020. Total will be looking to get involved in a US$4.6 billion Moroccan LNG import project and a US$3.9 billion gas-to-power development in South Africa.
  • Greece will be launching a tender this month for the privatisation of the country’s natural gas grid operator DESFA, part of a condition of Greece’s bailout agreement with the EU and IMF. Azerbaijan’s SOCAR originally agreed to buy 66% of DESFAfor €400 million, but the deal later collapsed.

Last week in Asian oil

Upstream

  • Pakistan’s OGDC has struck oil in the Chabaro-1 well in Pakistan’s Khewari block. Test drilling has shown flows of 15 mcf/d and a tiny 20 bpd of condensate. This adds on to the Chhutto-1 well, also in the province of Sindh, with flows of 8.66 mcf/d of gas and 285 bpd of condensate. While small, the finds are also a signal that OGDC’s aggressive exploration is paying off, adding to its production level of 50 kb/d – representing half of Pakistan’s current oil output.

Downstream

  • In an unusual and coordinated move, an alliance of more than 20 of China’s largest independent oil refiners have urged the ‘teapots’ to work closely as a group to adhere to government rules on oil quotas and fuel taxes. Previously pursuing individual agendas, the importance of the teapots in domestic fuels and exports expanded in 2015 when they were first allowed to import crude directly. But with that came extra scrutiny. Accused by Sinopec and Petrochina of evading or under-paying taxes, the move is an attempt to band together and act as a single block to preserve and defend their interests as a whole, since the actions of a single errant member could cause negative consequences for all.
  • Iraq is planning to triple its refining capacity by 2021 to reduce its reliance on refined product imports. Capitalising on its vast crude reserves, Iraq is planning a second refinery in Basra (300kb/d), a 70 kb/d plant in Kirkuk, and a 150 kb/d facility with two Chinese companies, as well as upgrades to existing refineries in Basra and Daura. Assuming all projects are completed as scheduled by 2021, processing capacity in Iraq will rise from 500 kb/d to 1.5 mmb/d.
  • Financing issues have caused Indonesia’s Pertamina to rethink its schedule of upcoming refinery upgrades and its ventures with Rosneft and Saudi Aramco. Unable to juggle so many projects within a short period, the timeline will now be expanded to ensure that cost is not a burden concentrated within 1 or 2 years. The Balikpapan project, which would boost capacity to 360 kb/d from 260 kb/d has been pushed back to 2020 from 2019, with a second stage – aimed at improving fuel quality – delayed to 2021. The Cilacap upgrade project will be pushed to 2023 from 2021, pending Saudi Aramco sign-off, while the grassroots 300 kb/d Tuban refinery with Rosneft is likely to be moved to 2024 from 2021. All this will mean that Indonesia will remain highly dependent on fuel imports for the time being.

Natural Gas & LNG

  • As Australia aims to ease the gas shortage in its populous east coast, the Northern Territory has ok-ed the building of the Jemena A$800 million gas pipeline (owned by the State Grid Corp of China and Singapore Power), which will link the gasfields in northern Australia with consuming markets in Queensland. Meanwhile, further south, the state of Victoria is backing a floating LNG import project with AGL Energy to beef up its local gas supply. This is required since onshore gas drilling has been barred in Victoria, forcing the state to compete with LNG export projects pulling natural gas out of the country’s manufacturing hub.

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Upcoming OPEC Meeting: What to Expect

A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.

That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.

That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.

Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.

Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?

Expectations at the 176th OPEC Conference

  • 25 June 2019, Vienna, Austria
  • Extension of current OPEC+ supply deal from end-June 2019 to end-December 2019
June, 12 2019
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • Brent crude oil spot prices averaged $71 per barrel (b) in May, largely unchanged from April 2019 and almost $6/b lower than the price in May of last year. However, Brent prices fell sharply in recent weeks, reaching $62/b on June 5. EIA forecasts Brent spot prices will average $67/b in 2019, $3/b lower than the forecast in last month’s STEO, and remain at $67/b in 2020. EIA’s lower 2019 Brent price path reflects rising uncertainty about global oil demand growth.
  • EIA forecasts global oil inventories will decline by 0.3 million barrels per day (b/d) in 2019 and then increase by 0.3 million b/d in 2020. Although global liquid fuels demand outpaces supply in 2019 in EIA’s forecast, global liquid fuels supply is forecast to rise by 2.0 million b/d in 2020, with 1.4 million of that growth coming from the United States. Global oil demand rises by 1.4 million b/d in 2020 in the forecast, up from expected growth of 1.2 million b/d in 2019.
  • Annual U.S. crude oil production reached a record 11.0 million b/d in 2018. EIA forecasts that U.S. production will increase by 1.4 million b/d in 2019 and by 0.9 million b/d in 2020, with 2020 production averaging 13.3 million b/d. Despite EIA’s expectation for slowing growth, the 2019 forecast would be the second-largest annual growth on record (following 1.6 million b/d in 2018), and the 2020 forecast would be the fifth-largest growth on record.
  • For the 2019 summer driving season, which runs from April through September, EIA forecasts that U.S. regular gasoline retail prices will average $2.76 per gallon (gal), down from an average of $2.85/gal last summer. The lower forecast gasoline prices primarily reflect EIA’s expectation of lower crude oil prices this summer.

U.S. residential electricity price

West Texas Intermediate (WTI) crude oil price

World liquid fuels production and consumption balance


Natural gas

  • The Henry Hub natural gas spot price averaged $2.64/million British thermal units (MMBtu) in May, almost unchanged from April. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019. EIA expects Henry Hub natural gas spot prices will average $2.77/MMBtu in 2019, down 38 cents/MMBtu from 2018. EIA expects natural gas prices in 2020 will again average $2.77/MMBtu.
  • EIA forecasts that U.S. dry natural gas production will average 90.6 billion cubic feet per day (Bcf/d) in 2019, up 7.2 Bcf/d from 2018. EIA expects natural gas production will continue to grow in 2020, albeit at a slower rate, averaging 91.8 Bcf/d next year.
  • U.S. natural gas exports averaged 9.9 Bcf/d in 2018, and EIA forecasts that they will rise by 2.5 Bcf/d in 2019 and by 2.9 Bcf/d in 2020. Rising exports reflect increases in liquefied natural gas exports as new facilities come online. Rising natural gas exports are also the result of an expected increase in pipeline exports to Mexico.
  • EIA estimates that natural gas inventories ended March at 1.2 trillion cubic feet (Tcf), 15% lower than levels from a year earlier and 28% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections will outpace the previous five-year average during the 2019 April-through-October injection season and that inventories will reach almost 3.8 Tcf at the end of October, which would be 17% higher than October 2018 levels and about equal to the five-year average.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants to rise from 35% in 2018 to 37% in 2019 and to 38% in 2020. EIA forecasts that the share of generation from coal will average 24% in 2019 and 23% in 2020, down from 27% in 2018. The forecast nuclear share of generation falls from 20% in 2019 to 19% in 2020, reflecting the retirement of some nuclear reactors. Hydropower averages a 7% share of total generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables together provided 10% of U.S. generation in 2018. EIA expects they will provide 11% in 2019 and 13% in 2020.
  • EIA forecasts that renewable fuels, including wind, solar, and hydropower, will collectively produce 18% of U.S. electricity in 2019 and almost 20% in 2020. EIA expects that annual generation from wind will surpass hydropower generation for the first time in 2019 to become the leading source of renewable electricity generation and maintain that position in 2020.
  • EIA forecasts that U.S. coal consumption, which reached a 39-year low of 687 million metric tons (MMst) in 2018, will fall to 602 MMst in 2019 and to 567 MMst in 2020. The falling consumption reflects lower demand for coal in the electric power sector.
  • After rising by 2.7% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 2.0% in 2019 and by 0.9% in 2020. EIA expects U.S. CO2 emissions will fall in 2019 and in 2020 because its forecast assumes that temperatures will return to near normal, and because the forecast share of electricity generated from natural gas and renewables increases while the forecast share generated from coal, which produces more CO2 emissions, decreases. Energy-related CO2 emissions are sensitive to weather, economic growth, energy prices, and fuel mix.

U.S. natural gas prices


U.S. residential electricity price

West Texas Intermediate (WTI) crude oil price

June, 12 2019
Sempra Energy ships first liquefied natural gas cargo from Cameron LNG export facility

U.S. LNG export capacity

Source: U.S. Energy Information Administration, U.S. liquefaction capacity database

On May 31, 2019, Sempra Energy, the majority owner of the Cameron liquefied natural gas (LNG) export facility, announced that the company had shipped its first cargo of LNG, becoming the fourth such facility in the United States to enter service since 2016. Upon completion of Phase 1 of the Cameron LNG project, U.S. baseload operational LNG-export capacity increased to about 4.8 billion cubic feet per day (Bcf/d).

Cameron LNG’s export facility is located in Hackberry, Louisiana, next to the company’s existing LNG-import terminal. Phase 1 of the project includes three liquefaction units—referred to as trains—that will export a projected 12 million tons per year of LNG exports, or about 1.7 Bcf/d.

Train 1 is currently producing LNG, and the first LNG shipment departed the facility aboard the ship Marvel Crane. The facility will continue to ship commissioning cargos until it receives approval from the Federal Energy Regulatory Commission to begin commercial shipments. Commissioning cargos refer to pre-commercial cargo loaded while export facility operations are still undergoing final testing and inspection. Trains 2 and 3 are expected to come online in the first and second quarters of 2020, according to Sempra Energy’s first-quarter 2019 earnings call.

Cameron LNG has regulatory approval to expand the facility through two additional phases, which involve the construction of two additional liquefaction units that would increase the facility’s LNG capacity to about 3.5 Bcf/d. These additional phases do not have final investment decisions.

Cameron LNG secured an authorization from the U.S. Department of Energy to export LNG to Free Trade Agreement (FTA) countries as well as to countries with which the United States does not have Free Trade Agreements (non-FTA countries). A considerable portion of the LNG shipments is expected to fulfill long-term contracts in Asian countries, similar to other LNG-export facilities located in the Gulf of Mexico region.

Cameron LNG will be the fourth U.S. LNG-export facility placed into service since February 2016. LNG exports rose steadily in 2016 and 2017 as liquefaction trains at the Sabine Pass LNG-export facility entered service, with additional increases through 2018 as units entered service at Cove Point LNG and Corpus Christi LNG. Monthly exports of LNG exports reached more than 4.0 Bcf/d for the first time in January 2019.

U.S. LNG exports

Source: U.S. Energy Information Administration, Natural Gas Monthly

Currently, two additional liquefaction facilities are being commissioned in the United States—the Elba Island LNG in Georgia and the Freeport LNG in Texas. Elba Island LNG consists of 10 modular liquefaction trains, each with a capacity of 0.03 Bcf/d. The first train at Elba Island is expected to be placed into service in mid-2019, and the remaining nine trains will be commissioned sequentially during the following months. Freeport LNG consists of three liquefaction trains with a combined baseload capacity of 2.0 Bcf/d. The first train is expected to be placed in service during the third quarter of 2019.

EIA’s database of liquefaction facilities contains a complete list and status of U.S. liquefaction facilities.

June, 12 2019