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Last Updated: August 7, 2019
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Forecast HighlightsGlobal liquid fuels

  • Brent crude oil spot prices averaged $64 per barrel (b) in July, almost unchanged from the average in June 2019 but $10/b lower than the price in July of last year. EIA forecasts Brent spot prices will average $64/b in the second half of 2019 and $65/b in 2020. The forecast of stable crude oil prices is the result of EIA’s expectations of a relatively balanced global oil market. EIA forecasts global oil inventories will increase by 0.1 million barrels per day (b/d) in 2019 and 0.3 million b/d in 2020.
  • EIA expects West Texas Intermediate (WTI) crude oil prices will average $5.50/b less than Brent prices during the fourth quarter of 2019 and in 2020, narrowing from the $6.60/b spread during July. The narrowing spread reflects EIA’s assumption that crude oil pipeline transportation constraints from the Permian Basin to refineries and export terminals on the U.S. Gulf Coast will ease in the coming months. In the July STEO, EIA forecast the Brent-WTI spread to average $4.00/b in 2020. The updated differential forecast reflects EIA’s revised assumptions about the marginal cost of moving crude oil via pipeline from Cushing, Oklahoma, to the Gulf Coast.
  • EIA estimates that U.S. crude oil production averaged 11.7 million b/d in July, down by 0.3 million b/d from the June level. The declines were mostly in the Federal Gulf of Mexico (GOM), where operators shut platforms for several days in mid-July because of Hurricane Barry. EIA estimates that GOM crude oil production fell by more than 0.3 million b/d in July. Those declines were partially offset by the Lower 48 States onshore region, which is mostly tight oil production, where supply rose by more than 0.1 million b/d. EIA expects monthly growth in Lower 48 onshore production to slow during the rest of the forecast period, averaging 50,000 b/d per month from the fourth quarter of 2019 through the end of 2020, down from an average of 110,000 b/d per month from August 2018 through July 2019. EIA forecasts U.S. crude oil production will average 12.3 million b/d in 2019 and 13.3 million b/d in 2020, both of which would be record levels.
  • U.S. regular gasoline retail prices averaged $2.74 gallon (gal) in July, up 2 cents/gal from June but 11 cents/gal lower than the average in July of last year. EIA expects that monthly average gasoline prices peaked for the year in May at an average of $2.86/gal and will fall to an average of $2.64/gal in September. EIA expects regular gasoline retail prices to average $2.62/gal in 2019 and $2.71/gal in 2020.

Natural gas

  • The Henry Hub natural gas spot price averaged $2.37/million British thermal units (MMBtu) in July, down 3 cents/MMBtu from June. However, by the end of the month, spot prices had fallen below $2.30/MMBtu. Based on this price movement and EIA’s forecast of continued strong growth in natural gas production, EIA lowered its Henry Hub spot price forecast for the second half of 2019 to an average of $2.36/MMBtu. In the July STEO, EIA expected prices to average $2.50/MMBtu during this period. EIA expects natural gas prices in 2020 will increase to an average of $2.75/MMBtu. EIA’s natural gas production models indicate that rising prices are required in the coming quarters to bring supply into balance with rising domestic and export demand in 2020.
  • EIA forecasts that U.S. dry natural gas production will average 91.0 billion cubic feet per day (Bcf/d) in 2019, up 7.6 Bcf/d from 2018. EIA expects monthly average natural gas production to grow in late 2019 and then decline slightly during the first quarter of 2020 as the lagged effect of low prices in the second half of 2019 reduces natural gas-directed drilling. However, EIA forecasts that growth will resume in the second quarter of 2020, and natural gas production in 2020 will average 92.5 Bcf/d.
  • EIA estimates that natural gas inventories ended July at 2.7 trillion cubic feet (Tcf), 13% higher than levels from a year earlier and 4% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections during the 2019 April-through-October injection season will outpace the previous five-year average and that inventories will rise to more than 3.7 Tcf at the end of October, which would be 16% higher than October 2018 levels and slightly above to the five-year average.

Electricity, coal, renewables, and emissions

  • EIA has expanded its forecasts for electricity supply in the United States and has introduced new forecasts for wholesale electricity prices. A STEO Supplement provides more information about the changes.
  • Lower costs for natural gas drive EIA’s forecast that annual average wholesale electricity prices will be lower in 2019 than last year in all areas of the United States. The forecast year-over-year declines range from -0.2% in the Southwest Power Pool (SPP) to -28% in the Electric Reliability Council of Texas (ERCOT) market.
  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and then decline slightly in 2020. EIA forecasts that the share of U.S. generation from coal will average 24% in 2019 and in 2020, down from 28% in 2018. The forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables together provided 10% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects electric power sector demand for coal to fall by 2% in 2020, compared with an expected decline of 15% in 2019. However, planned coal plant retirements will continue to put downward pressure on overall electricity demand for the fuel. Almost 13 gigawatts of coal-fired electricity generation capacity has retired this year or is scheduled to retire by the end of 2020, accounting for 5% of the capacity existing at the end of 2018.
  • EIA forecasts that renewable fuels, including wind, solar, and hydropower, will collectively produce 18% of U.S. electricity in 2019 and 19% 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 is improving its regional-level trend analysis by inserting a generator-level production cost model that simulates hourly generation at individual power plants. This improves our insight into generation, especially from fast-growing renewable sources like wind and solar.
  • This additional granularity and the assumption that wind will return to more normal levels in 2019, after a windy first half of 2018, results in an EIA forecast that electricity generation from wind power will average 295 billion kilowatthours (kWh) in 2019 and 335 billion kWh in 2020, estimates that are 4% and 7% lower, respectively, than forecast in the July STEO. In addition, the application of hourly dispatch that better models solar incidence lowers the solar electric production forecast by 1.1% in 2019 and by 2.8% in 2020.
  • EIA forecasts that, after rising by 2.7% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 2.3% in 2019 and by 0.5% in 2020. In 2019, EIA forecasts that space cooling demand (as measured in cooling degree days) will be lower than in 2018, when it was 13% higher than the previous 10-year (2008–17) average. In addition, in 2019, EIA expects U.S. CO2 emissions to decline because the forecast share of electricity generated from natural gas and renewables is increasing while the forecast share generated from coal, which is a more carbon-intensive energy source, is decreasing. EIA’s projected emissions decline is lower in 2020 than in 2019 because it forecasts that both heating and cooling requirements will be slightly lower than normal. At the same time, the forecast coal share of generation will remain about the same as in 2019 while the natural gas share declines. Although EIA forecasts that generation from renewables will continue to increase in 2020, a forecast decrease in nuclear power offsets 24% of the renewables’ gain.

Changes to the August STEO

Beginning with the August 6, 2019, publication of the STEO, EIA has expanded its forecasts for regional electricity supply in the United States and has introduced new forecasts for wholesale electricity prices. 

To better present the expanded forecast, EIA will no longer publish table 7e, and the data in tables 7a, 7b, 7d, and 8b will now be stated in billion kilowatthours.

EIA has posted a STEO Supplement that provides more information about the new electricity supply and wholesale price forecasts.

Price Summary
 2017201820192020
aWest Texas Intermediate.
bAverage regular pump price.
cOn-highway retail.
dU.S. Residential average.
WTI Crude Oila
(dollars per barrel)
50.7965.0657.8759.50
Brent Crude Oil
(dollars per barrel)
54.1571.1965.1565.00
Gasolineb
(dollars per gallon)
2.422.732.622.71
Dieselc
(dollars per gallon)
2.653.183.073.22
Heating Oild
(dollars per gallon)
2.513.012.993.07
Natural Gasd
(dollars per thousand cubic feet)
10.8610.4910.4910.61
Electricityd
(cents per kilowatthour)
12.8912.8913.0513.17

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Your Weekly Update: 12 - 16 August 2019

Market Watch 

Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b

  • Saudi Arabia’s overtures to further stabilise prices was met with a largely positive response by the market, allowing crude prices to claw back some ground after being hammered by demand concerns
  • Saudi officials reportedly called other members in the OPEC and OPEC+ producer clubs to discuss options on how to stem the recent rout in prices, with an anonymous official quoted as saying that it ‘would not tolerate continued price weakness’
  • Reports suggest that Saudi Arabia plans to keep its oil exports at below 7 mmb/d in September according to sales allocations, which was seen as a stabilising factor in crude price trends
  • This came after crude prices fell as the US-China trade war entered a new front, causing weakness in the Chinese Yuan, although President Trump has floated the idea of delaying the new round of tariffs beyond the current implementation timeline of September 1
  • Crude had also fallen in response to a slide in American crude oil stockpiles and a receding level of tensions in the Persian Gulf
  • In a new report, the International Energy Agency said that the outlook for global oil demand is ‘fragile’ on signs of an economic slowdown; there is also concern that China will target US crude if the US moves ahead with its tariff plan
  • The US active rig count lost another 8 rigs – 6 oil and 2 gas – the sixth consecutive weekly loss that brought the total number of active rigs to 934
  • Demand fears will continue to haunt the market, which will not be offset so easily of Saudi-led efforts to limit production; as a result, crude prices will trade rangebound with a negative slant in the US$56-58/b range for Brent and US$52-54/b for WTI


Headlines of the week

Upstream

  • Nearly all Anadarko shareholders have approved the Occidental Petroleum deal, completing the controversial takeover bid despite investor Carl Icahn’s attempts to derail the purchase
  • Crude oil inventories in Western Canada have fallen by 2.75 million barrels m-o-m to its lowest level since November 2017, as the production limits in Alberta appear to be doing their job in limiting a supply glut while output curbs are slowly being loosened on the arrival of more rail and pipeline capacity
  • Mid-sized Colorado players PDC Energy and SRC Energy – both active in the Denver-Julesburg Basin – are reportedly in discussion to merge their operations
  • Pemex has been granted approval by the National Hydrocarbon Commission to invest US$10 billion over 25 years to develop onshore and offshore exploration opportunities in Mexico
  • Qatar Investment Authority has acquired a ‘significant stake’ in major Permian player Oryx Midstream Services from Stonepeak Infrastructure Partners for some US$550 million, as foreign investment in the basin increases
  • PDVSA and CNPC’s Venezuelan joint venture Sinovensa has announced plans to expand blending capacity – lightening up extra-heavy Orinoco crude to medium-grade Merey – from a current 110,000 b/d to 165,000 b/d
  • BHP has approved an additional US$283 million in funding for the Ruby oil and gas project in Trinidad and Tobago, with first production expected in 2021
  • CNPC, ONGC Videsh and Petronas have reportedly walked away from their onshore acreage in Sudan, blaming unpaid oil dues on production from onshore Blocks 2A and 4 that have already reached more than US$500 million

Midstream/Downstream

  • Expected completion of Nigeria’s huge planned 650 kb/d Dangote refinery has been delayed to the end of 2020, with issues importing steel and equipment cited
  • Saudi Aramco’s US refining arm Motiva announced plans to shut several key units at its 607 kb/d Port Arthur facility in Texas for a 2-month planned maintenance, affecting its 325 kb/d CDU and the naphtha processing plant
  • ADNOC has purchased a 10% stake in global terminal operator VTTI, expanding its terminalling capacity in Asia, Africa and Europe
  • A little-known Chinese contractor Wison Engineering Services has reportedly agreed to refurbish Venezuela’s main refineries in a barter deal for oil produced, in a bid for Venezuela to evade the current US sanctions on its crude exports
  • Swiss downstream player Varo Energy will increase its stake in the 229 kb/d Bayernoil complex in Germany to 55% after purchasing BP’s 10% stake
  • India has raised the projected cost estimate of its giant planned refinery in Maharashtra – a joint venture between Indian state oil firms with Saudi Aramco and ADNOC – to US$60 billion, after farmer protests forced a relocation

Natural Gas/LNG

  • The government of Australia’s New South Wales has given its backing to South Korea’s Epik and its plan to build a new LNG import terminal in Newcastle
  • Kosmos Energy is proposing to build two new LNG facilities to tap into deepwater gas resources offshore Mauritania and Senegal under development
  • In the middle of the Pacific, the French territory of New Caledonia has started work on its Centrale Pays Project, a floating LNG terminal with an accompanying 200-megawatt power plant, with Nouvelle-Caledonia Energie seeking a 15-year LNG sales contract for roughly 200,000 tons per year
August, 16 2019
The State of the Industry: Q2 2019

The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.

In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.

As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.

 After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.

And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.

So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.

Supermajor Financials: Q2 2019

  • ExxonMobil – Revenue (US$69.1 billion, down 6% y-o-y), Net profit (US$3.1 billion, down 22.5% y-o-y)
  • Shell - Revenue (US$90.5 billion, down 6.5% y-o-y), Net profit (US$3 billion, down 50% y-o-y)
  • Chevron – Revenue (US$36.3 billion, down 10.4% y-o-y), Net profit (US$4.3 billion, up 26% y-o-y)
  • BP - Revenue (US$73.7 billion, down 4.11% y-o-y), Net profit (US$2.8 billion, flat y-o-y)
  • Total - Revenue (US$51.2 billion, down 2.5% y-o-y), Net profit (US$2.89 billion, down 18.6% y-o-y)
August, 14 2019
TODAY IN ENERGY: Australia is on track to become world’s largest LNG exporter

LNG exports from selected countries

Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker

Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.

Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.

Australia LNG export capacity

Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.

Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.

Australia LNG projects

Source: U.S. Energy Information Administration

Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.

Australia LNG exports by destination country

Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)

For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.

Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.

August, 14 2019