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Last Updated: November 22, 2017
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Market Watch

Headline crude prices for the week beginning 20 November 2018 – Brent: US$62/b; WTI: US$56/b

  • Mixed signals out of OPEC. Saudi Arabia says ‘too early to make assessment’ on extending oil output cuts, while Iran says majority of OPEC members support extending supply freeze
  • Decision on extending cuts beyond March 30, 2018 expected at OPEC Vienna meeting next week on November 30. Pact with NOPEC group (Russia and 9 other Non-OPEC countries) likely to continue
  • OPEC admits market ‘will not be balanced’ by March 2018 and expects supply deficit to increase next year on stronger-than-expected demand
  • Active US rig count up by 8, all gas-producing sites in Texas and Louisiana
  • Part of TransCanada’s Keystone pipeline shut after leak in South Dakota, but no impact on Nebraska’s approval of Keystone XL pipeline route
  • US EIA data points to growth in domestic crude and gasoline inventories, while US oil output hit a record 9.65 mmb/d last week
  • International Energy Agency expects the US to account for more than 80% of world crude supply growth through 2027
  • Norway’s US$1 trillion sovereign well fund proposes US$35 billion sell-off in oil and gas stocks, including ExxonMobil and Shell, rattling long-term confidence in the oil sector
  • Dollar gains against the Euro, as Angela Merkel’s talks to form the next German government fail, hitting commodities
  • Singapore onshore oil product stocks continue to swell, with light distillates up by 8.6% to 11.6 million barrels, placing pressure on Asian gasoline and naphtha prices
  • China raised retail gasoline prices on 18 November, the 10th increase in 2017 and second in November. Retail prices of gasoline up by CNY265 (US$40) per ton, diesel up by CNY250 (US$38) per ton
  • Crude price outlook: Crude prices likely to trend downwards over the week to US$60/b (Brent) and US$54/b (WTI) on rising American output and fretting over OPEC deal. Prices to stay rangebound until November 30 when clarity is expected on OPEC’s position. 


Headlines of the week

Upstream

  • After regaining the Bai Hasan and Avana oilfields from Kurdish regional government, Iraq plans to increase output in Kirkuk to 1 mmb/d, as negotiations with Turkey on the Kirkuk-Ceyhan pipeline continue
  • Murphy Oil strikes oil at the CM-1X well in its Block 15-1/05 in the Nam Con Son basin, the firm’s second oil discovery after CT-1X this year
  • Following lifting of US sanctions last month, Sudan has begun dialogue with Lukoil and several US/Canadian companies to develop its onshore oil industry, as well as natural gas projects in the Red Sea
  • Eni has signed a new PSC for offshore Block 52 in Oman, holding a 85% stake, in partnership with Oman Oil Company Exploration and Production

Downstream

  • Oman Oil Company has begun preliminary financial negotiations to back its planned 230 kb/d Duqm refinery, a joint venture with KPI
  • Saudi Arabia announced initial plans to build a refinery in Egypt, after serving as Egypt’s main oil product supplier since 2016
  • Petrobras is opening early discussions with China’s CNPC over the latter’s participation in reviving the stalled 165kb/d COMPERJ refinery and petrochemical project in Rio de Janeiro

Natural Gas/LNG

  • Anadarko’s Mozambique LNG project is approved by the government, as it signs a 20-year contract with Thailand’s PTT to supply 2.6 mtpa of LNG
  • Ahead planned March 2018 start of Ichthys, Japan’s Inpex awarded 100% exploration permit for Block WA-532-P in Western Australia, near Ichthys
  • Russia and Saudi Arabia have opened up talks on Saudi Aramco potentially collaborating in Novatek’s Arctic LNG 2 project, after PetroChina parent CNPC and China Development Bank bought in
  • Sinopec and China’s sovereign wealth fund sign up for 20 mtpa Alaska LNG export terminal project, par of a second wave of US LNG projects
  • China’s POLY-GCL Petroleum Group signs US$4 billion MoU with Djibouti for a natural gas project, comprising pipeline, liquefaction plant and export terminal in Damerjog. Gas to be transported from Ethiopia (12 bcm capacity), with LNG target capacity at an initial 3 mtpa in 2020
  • Egypt optimistic that it can halt all LNG imports by end-2018 and begin gas exports in 2019 as Zohr field begins producing at initial 350 mcf/d; Rosneft acquired almost 30% of the Eni-led Zohr in October, and announced plans to invest over US$2 billion through 2021 and possibly increase its stake to 35%
  • Premier UK is seeking to sell of a 25% stake in Indonesia’s Tuna gas field from its 65% stake to fund development. Output is expected to start in 2022, with Premier Oil having reached a deal to sell Tuna gas to Vietnam via a cross-border pipeline connection to Nam Con Son system

Corporate

  • Australia’s Santos Energy is now part of a bidding war, after a A$9.5 billion takeover from Harbour Energy was rejected, triggering further bids and an improved all-cash A$11 billion offer from Harbour
  • A law firm survey reveals that offshore service companies dominated North American energy industry bankruptcies in 2017, with 44 firms filing for bankruptcy owing US$24.8 billion

BP became the first major European energy firm to start a share buyback programme since 2014, a sign that years of austerity have paid off

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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