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Last Updated: September 21, 2017
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Business Trends

Last week in World Oil:


  • Oil prices remain close to multi-month highs as the market assesses the impact of two recent major hurricanes, as well as indications that OPEC is considering extending the current supply freeze deal beyond March 2018. Brent is trading at about US$55/b, while WTI stands at about US$50/b.


  • Uganda has signed the first exploration deal from its 2015 licensing round. Australia’s Armour Energy will be allowed to explore the Kanywataba block in the Albertine rift valley near the Democratic Republic of Congo. The block had previously been licensed to Total, CNOOC and Tullow Oil, which surrendered the block in 2012. Deals for the remaining five blocks offered at auction have yet to be finalised.
  • After acquiring exploration rights in Mexico’s first-ever deepwater auction in 2016, CNOOC is now searching for partners in a ‘farmout’ proposition that will offer a stake in return with drilling and production assistance. CNOOC holds the rights to two Gulf of Mexico blocks in the Perdido Fold Belt, where Mexico estimates the bulk of its untapped oil lies. One of the deepest exploration areas in the world, CNOOC cannot afford to go it alone, and is soliciting potential partners for the projects.
  • US drillers shut down seven oil rigs last week – the steepest cut since January 2017 – the latest indication that drilling recovery has stalled.  

Downstream & Midstream

  • The series of earthquakes roiling Mexico over the past two weeks has Wrecked Pemex’s refining network, causing fuel shortages and driving up price, which are no longer state-controlled. Output from three of its six refineries has been affected, removing up to 50% of national capacity. With Mexico’s nearest source of fuel imports – the US – also recovering from Hurricane Harvey, the tight situation could continue for a while.

Natural Gas and LNG

  • Nexen is shelving its proposed Aurora LNG export terminal on Canada’s west coast, citing a poor market environment and low prices. Owned by CNOOC since 2012, Nexen has been conducting a feasibility study into the project for four years, finally pulling out as global LNG prices do not look likely to gain strength for the foreseeable future. The project, with a capacity of 24 mtpa of LNG, is the third Canadian project to be cancelled, after the Petronas and Shell projects. With the political situation in British Columbia currently unfavourable to LNG projects, it appears that Canada’s ambitions to be a major LNG supplier to Asia is diminished.
  • Nigeria’s Shoreline has signed a US$300 million agreement with Shell to develop commercial natural gas infrastructure around Lagos. In line with Shell’s objective to focus more on gas than oil in Nigeria, the deal will be the two companies work together on developing distributing and selling piped natural gas to the city’s Victoria Island, Ikoyi, Lekki and Epe district, which constitute Lagos’ business hub and upscale residential areas.
  • Premier Oil will be selling off half of its stake in the North Sea’s Babbage gas field, as well as a 25% stake in the Cobra field, as it attempts to pare down debt accrued over the past three years. Both assets were gained last year through its US$120 million acquisition of E.ON’s North Sea business.

Last week in Asian oil


  • Italy’s Eni has signed a cooperation agreement with China’s CNPC, a move that could give the firm a greater foothold in the Chinese market. The broad agreement covers joint activities in upstream E&P, as well as LNG, trading, refining and petrochemicals – both within China and abroad. For Eni, this boosts its financial firepower as it looks to expand activities globally, while CNPC will have the benefit of an established partner with a long global history to help expand its international ambitions. This isn’t the first time both companies have worked together; in 2013, CNPC bought a 20% stake in Eni’s gas field offshore Mozambique – planned to eventually produce LNG for export to Asia – while both firms are also shareholders in Kazakhstan’s giant Kashagan oil field.
  • After a century of producing oil in Iraq, Shell is forsaking oil in favour of gas, citing low-margin production contracts. Shell will relinquish operations at the Majnoon field, after being offered new ‘unfavourable fiscal terms’, as well as selling its 20% stake in the West Qurna 1 oil field, which is operated by ExxonMobil. Instead, it will focus on developing and expanding the Basra Gas Company – in which it has a 44% stake - which processes gas from the Rumaila, West Qurna and Zubair fields.

Downstream & Midstream

  • Chinese refining output increased by 6.5% in August, rebounding from a low of 10.71 mmbpd in July. The rise comes as a new series of crude quotas was issued to China’s independent teapot refineries – causing a stampede to increase production – as well as the startup of PetroChina’s new 260 kb/d refinery in Yunnan. However, YTD refining output remains down y-o-y – at a -4.6% - as last year’s teapot refining bonanza tapers down to a more controlled pace at the state’s instigation.
  • In India, heavy rainfall causing severe flooding across the country has caused oil demand to fall by 6.1% y-o-y in August, to 15.75 million tons from 16.78 million tons. Gasoline and diesel have been particularly hard hit, as heavy waters impeded transportation and industrial traffic. Kerosene usage also shrank severely, by 41%, though this was more to do with the ongoing drive to replace it with LPG as a cooking fuel.

Natural Gas & LNG

  • Bangladesh has signed its first long-term LNG agreement, agreeing to import fuel from Qatar’s RasGas over 15 years. Initial supply will be at 1.8 mtpa for the first five years, followed by 2.5 mtpa for the remaining ten, which is less than the 4 mtpa figure bandied about when the initial Petrobangla and RasGas MoU emerged in 2011. Bangladesh will be looking to fill in that gap with spot purchases, as it battles with dwindling domestic production and the departure of Chevron from its waters.
  • The quest to build The Philippines’ first LNG import terminal continues to hit choppy waters, with the government now asking for ‘unsolicited private sectors proposals’, after deeming plans submitted by international players from Singapore, Japan, South Korea, China, Indonesia and the UAE (among others) ‘unsatisfactory’. The stumbling block, it appears, is the estimated price tag of US$2 billion and that state oil company PNOC failed to convince the proposers to accept its share of banked gas from the Malampaya field as equity for the terminal project.  

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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

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