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Last Updated: July 11, 2019
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In the July 2019 update of its Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that Brent crude oil prices will average $67 per barrel (b) in 2019 and in 2020. EIA expects that West Texas Intermediate (WTI) crude oil prices will average $60/b in 2019 and $63/b in 2020 (Figure 1). The forecast of relatively stable crude oil prices in the mid-$60/b range reflects EIA’s expectation that heading into 2020, global oil consumption will grow at a similar rate as global oil supply at current price levels. However, several risks to both consumption and supply could push prices out of this range.

Figure 1. Monthly Brent and West Texas Intermediate crude oil prices

Brent crude oil spot price averaged $64/b in June, down from an average of $71/b in both April and May. The recent price declines largely reflect increasing concerns about global oil demand growth as a result of increasingly weak global economic signals. Weakening global oil demand and strong supply growth in the United States contributed to global petroleum and other liquid fuels inventory builds in the first half of 2019 and limited any sustained upward pressure on crude oil prices. In terms of price formation in recent months, these factors have outweighed decreasing crude oil supply from members of the Organization of the Petroleum Exporting Countries (OPEC). OPEC output fell because of declining crude oil production in Venezuela and Iran, the extension of the agreement between OPEC and non-OPEC participants (OPEC+) through the first quarter of 2020, and Saudi Arabia’s continued over compliance with the existing OPEC+ agreements.

EIA expects that the combination of strong growth in U.S. and other non-OPEC liquid fuels production and slowing global oil demand growth will contribute to a balanced market in the second half of 2019 and about 150,000 barrels per day (b/d) growth in global petroleum and other liquid fuels inventories in 2020 (Figure 2). The global oil inventory builds in 2020 are expected to put some downward pressure on crude oil prices; however, EIA assumes that the downward pressure will be offset by upward price pressures as a result of the IMO 2020 regulations  going into effect. Although EIA expects the new regulations to have a limited impact on crude oil prices, many unknowns remain about how the global refining and shipping industries will respond to the regulation and how actual outcomes of these decisions will affect crude oil prices.

Figure 2. World liquid fuels production consumption balance

Developments regarding the rate of economic growth and its effect on global oil demand further contribute to crude oil price uncertainty. Based on forecasts from Oxford Economics, EIA lowered its global oil-weighted gross domestic product (GDP) growth projection to 2.2% in 2019, which would be the lowest annual growth rate since 2009. The low GDP growth rate, in turn, is expected to result in an annual oil consumption growth of 1.1 million b/d, the lowest level of growth since 2011 and similar to growth levels seen in 2016.

EIA forecasts that both economic growth and liquid demand growth will rebound in 2020. Annual oil-weighted GDP growth is expected to increase to 2.7% in 2020, leading to increased oil demand growth. EIA expects world liquid fuels demand growth of more than 1.4 million b/d in 2020, more than two-thirds of which is forecast to come collectively from China, the United States, India, and Russia.

On the supply side, EIA expects continuing declines (albeit at a slower pace) in OPEC production to be more than offset by supply growth in the United States and other non-OPEC countries. However, compliance with OPEC+ production targets and the potential for supply disruptions in key oil-producing countries could pose risks to the forecast.

On July 2, 2019, OPEC+ extended production cuts announced in December 2018 through the end of the first quarter of 2020. EIA’s forecast assumes the OPEC+ agreement will remain in place through the end of the first quarter of 2020, with OPEC+ continuing to target a balanced market after that. The degree of adherence to production targets from the OPEC+ agreement will be a key determinant of whether global crude oil inventories remain higher than the five-year (2014–18) average during the forecast period and will be a significant driver of crude oil prices. EIA forecasts OPEC total liquids production will average 35.3 million b/d in the second half of 2019 and 34.8 million b/d in 2020, down from 37.3 million b/d in 2018. The decline through 2019 to date is mainly the result of Saudi Arabia’s over compliance with the December 2018 OPEC+ agreement and rapidly decreasing crude oil production in Iran and Venezuela. Combined production in Iran and Venezuela fell to an estimated 2.8 million b/d as of June 2019, a 2.4 million b/d decrease compared with June 2018. These factors contributed to OPEC’s crude oil production averaging 29.9 million b/d in June, the lowest level since mid-2014.

Additional supply disruptions may potentially remove large volumes of crude oil from the global market and cause crude oil prices to increase. Events in Venezuela and Libya, in particular, could cause production to drop quickly. In Venezuela, widespread power outages, long-term inefficient management of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and state-owned Petróleos de Venezuela (PdVSA) have all contributed to accelerating declines. Although Libya’s crude oil production increased during the first half of 2019, supply disruptions will remain a significant risk through 2020 because of the tentative security situation in the country and the lack of investment in existing infrastructure. Disruptions to shipping through the Strait of Hormuz would also cause prices to increase.

Finally, the U.S. tight oil sector continues to be dynamic, and quickly evolving trends in this sector could affect both current crude oil prices and expectations for future prices. EIA expects U.S. crude oil production, which reached a record-high 11.0 million b/d in 2018, to average 12.4 million b/d in 2019 and 13.3 million b/d in 2020. Much of the growth in U.S. crude oil production is attributable to tight oil formations in the Permian region of Texas and New Mexico, which account for 950,000 b/d of the U.S. growth expected in 2019 and 740,000 b/d of the growth in 2020. A downside risk to Permian crude oil production is the increased production of natural gas from this region. Drilling in areas with high concentrations of natural gas in the Permian region might increase only if natural gas pipeline constraints are eased and tighter flaring limits are not implemented.

U.S. average regular gasoline and diesel prices increase

The U.S. average regular gasoline retail price increased 3 cents from the previous week to $2.74 per gallon on July 8, 11 cents lower than the same time last year. The Gulf Coast price increased 5 cents to $2.42 per gallon, and the Midwest and East Coast prices each increased nearly 4 cents to $2.67 per gallon and $2.66 per gallon, respectively. The Rocky Mountain price fell nearly 3 cents to $2.80 per gallon, and the West Coast price fell nearly 1 cent to $3.38 per gallon.

The U.S. average diesel fuel price increased more than 1 cent to $3.06 per gallon on July 8, 19 cents lower than a year ago. The Midwest price increased over 4 cents to $2.97 per gallon, and the East Coast and the Gulf Coast prices each increased less than 1 cent, remaining at $3.08 per gallon and $2.80 per gallon, respectively. The Rocky Mountain price fell nearly 2 cents to $2.98 per gallon, and the West Coast price fell less than 1 cent to $3.62 per gallon.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 0.2 million barrels last week to 76.9 million barrels as of July 5, 2019, 5.7 million barrels (7.9%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Midwest and Gulf Coast inventories decreased by 0.4 million barrels and 0.2 million barrels, respectively, while Rocky Mountain/West Coast inventories decreased slightly, remaining virtually unchanged. East Coast inventories increased by 0.4 million barrels. Propylene non-fuel-use inventories represented 6.0% of total propane/propylene inventories.

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SHORT-TERM ENERGY OUTLOOK
Forecast HighlightsGlobal liquid fuels
  • Brent crude oil spot prices averaged $63 per barrel (b) in November, up $3/b from October. EIA forecasts Brent spot prices will average $61/b in 2020, down from a 2019 average of $64/b. EIA forecasts that West Texas Intermediate (WTI) prices will average $5.50/b less than Brent prices in 2020. EIA expects crude oil prices will be lower on average in 2020 than in 2019 because of forecast rising global oil inventories, particularly in the first half of next year.
  • On December 6, the Organization of the Petroleum Exporting Countries (OPEC) and a group of other oil producers announced they were deepening production cuts originally announced in December 2018. The group is now targeting production that is 1.7 million barrels per day (b/d) lower than in October 2018, compared with the former target reduction of 1.2 million b/d. OPEC announced that the cuts would be in effect through the end of March 2020. However, EIA assumes that OPEC will limit production through all of 2020, amid a forecast of rising oil inventories. EIA forecasts OPEC crude oil production will average 29.3 million b/d in 2020, down by 0.5 million b/d from 2019.
  • Beginning on January 1, 2020, the International Maritime Organization (IMO) is set to enact Annex VI of the International Convention for the Prevention of Pollution from Ships (MARPOL Convention), which lowers the maximum sulfur content of marine fuel oil used in ocean-going vessels from 3.5% of weight to 0.5%. EIA expects that starting in the fourth quarter of 2019, this regulation will encourage global refiners to increase refinery runs and maximize upgrading of high-sulfur heavy fuel oil into low-sulfur distillate fuel to create compliant bunker fuels. EIA forecasts that U.S. refinery runs will rise by 3% from 2019 to a record level of 17.5 million b/d in 2020, resulting in refinery utilization rates that average 93% in 2020. EIA expects one of the most significant effects of the regulation to be on diesel wholesale margins, which rise from an average of 45 cents per gallon (gal) in 2019 to a forecasted peak of 61 cents/gal in the first quarter of 2020 and an average of 57 cents/gal in 2020.
  • EIA data show that the United States exported 90,000 b/d more total crude oil and petroleum products in September than it imported. This is the first month recorded in U.S. data that the United States exported more crude oil and petroleum products than it imported. U.S. imports and exports records of crude oil and petroleum products started on an annual basis in 1949 and on a monthly basis in 1973. EIA expects total crude oil and petroleum net exports to average 570,000 b/d in 2020 compared with average net imports of 490,000 b/d in 2019.
  • EIA expects U.S. crude oil production to average 13.2 million b/d in 2020, an increase of 0.9 million b/d from the 2019 level. Expected 2020 growth is slower than 2018 growth of 1.6 million b/d and 2019 growth of 1.3 million b/d. Slowing crude oil production growth results from a decline in drilling rigs over the past year that EIA expects to continue into 2020. Despite the decline in rigs, EIA forecasts production will continue to grow as rig efficiency and well-level productivity rises, offsetting the decline in the number of rigs.
  • EIA estimates that propane inventories in the Midwest—Petroleum Administration for Defense District (PADD) 2—were 22.0 million barrels at the end of November, 17% lower than the five-year (2014–18) average for the end of November. Colder-than-normal temperatures and strong grain drying demand in November contributed to large draws on Midwest propane inventories. Also, Western Canadian rail shipments of propane to the Midwest have declined since the opening of a new propane export terminal in Western Canada in May. EIA forecasts Midwest inventories at the end of March will be 32% lower than the five-year (2015–19) average and the lowest for that time of year since 2014.

West Texas Intermediate (WTI) crude oil price

Natural gas
  • EIA estimates that the U.S. total working gas inventories were 3,616 billion cubic feet (Bcf) at the end of November. This level was about equal to the five-year (2014–18) average and 19% higher than a year ago. EIA expects storage withdrawals to total 1.9 trillion cubic feet (Tcf) from the end of October to the end of March, which is less than the five-year average winter withdrawal. A withdrawal of this amount would leave the end-of-March inventories at almost 1.9 Tcf, which would be 8% higher than the five-year (2015–19) average.
  • The U.S. benchmark Henry Hub natural gas spot price averaged $2.64 per million British thermal units (MMBtu) in November, up 31 cents/MMBtu from October. Prices increased as a result of November temperatures that were colder than the 10-year (2009–18) average. EIA forecasts the Henry Hub spot price to average $2.45/MMBtu in 2020, down 14 cents/MMBtu from the 2019 average.
  • EIA forecasts that annual U.S. dry natural gas production will average 92.1 billion cubic feet per day (Bcf/d) in 2019, up 10% from 2018. EIA expects that natural gas production will grow much less in 2020 because of the lag between changes in price and changes in future drilling activity. Low prices in the third quarter of 2019 will reduce natural gas-directed drilling in the first half of 2020. EIA forecasts natural gas production in 2020 will average 95.1 Bcf/d.

World liquid fuels production and consumption balance

Electricity, coal, renewables, and emissions
  • 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 to 39% in 2020. EIA forecasts the share of U.S. electric generation from coal to average 25% in 2019 and 22% in 2020, down from 28% in 2018. EIA’s 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 provided 9% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects U.S. coal production in 2019 to total 697 million short tons (MMst), which would be an 8% decline from the 2018 level. In 2020, EIA expects a further decrease in total U.S. coal production of 14%, to an annual total of 601 MMst, reflecting continued idling and closures of mines as a result of declining domestic demand.
  • EIA expects U.S. coal exports to total 93 MMst in 2019, and then decline by 8 MMst to 85 MMst in 2020. U.S. coking coal currently faces challenges from a global oversupply of steel, particularly in the fourth quarter of 2019. Steam coal exports have been dampened by high stockpiles in Europe and India, a top destination for U.S. shipments.
  • EIA expects U.S. electric power sector generation from renewables other than hydropower—principally wind and solar—to grow from 411 billion kilowatthours (kWh) in 2019 to 471 billion kWh in 2020. In EIA’s forecast, Texas accounts for 20% of the U.S. nonhydropower renewables generation in 2019 and 22% in 2020. California’s forecast share of nonhydropower renewables generation falls from 15% in 2019 to 14% in 2020. EIA expects that the Midwest and Central power regions will see shares in the 16% to 18% range for 2019 and 2020.
  • EIA forecasts that, after rising by 2.9% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.4% in 2019 and by 2.2% in 2020, partly as a result of lower forecast energy consumption. For 2019, EIA estimates there was less demand for space cooling because of cooler summer months, with an estimated 5% decline in U.S. cooling degree days from 2018, when temperatures were significantly higher than the previous 10-year (2008–17) average. In addition, EIA also expects U.S. CO2 emissions in 2019 to decline because the forecast share of electricity generated from natural gas and renewables will increase, and the share generated from coal, which is a more carbon-intensive energy source, will decrease.

U.S. natural gas prices

U.S. residential electricity price

December, 11 2019
INDONESIA’S DECOMMISSIONING CHALLENGE REPORT

A report by Nicholas Newman

Many of Indonesia’s oil and gas fields, both on and offshore, are coming to the end of their commercially viable operational lifespan. More than 60% of Indonesia’s oil and more than 30% of gas production comes from late-life-cycle resources spread across the world's largest island country. Despite investment and use of enhanced oil field recovery measures, as well as increasing automation to extend the economic lifespan of these assets, decommissioning will soon become necessary.

However Indonesia, like many countries new to the prospect of decommissioning energy infrastructure, face many key technological, fiscal, environmental, regulatory and industrial capacity issues, which need to be addressed by both government and industry decision makers.

This report, commissioned by the consulting and advisory arm of London and Aberdeen based Precision Media & Communications, aims to take a look at many of the issues Indonesia and other South East Asian oil producing nations are likely to face with the prospect of decommissioning the region's oil and gas aging energy infrastructure both onshore and offshore... To find out more Click here

December, 09 2019
Compliance Is Critical

The signs going into OPEC’s bi-annual meeting in Vienna were broadly positive. On one hand, you had some key members – including Iraq, surprisingly – stating the need for the broader OPEC+ club to make further cuts to its supply deal. On the other hand, there was Saudi Arabia, which needed a win to support Saudi Aramco’s upcoming IPO. What emerged was a little something for everyone, that was still broadly positive but scant on the details.

The headlines spinning out of the December 5 meeting was that the OPEC+ alliance agreed to slash a further 500,000 b/d, with Saudi Arabia pledging an additional voluntary cut of 400,000 b/d. Collectively, this would raise the club’s total supply reduction to 2.1 mmb/d – or over 2% of global oil demand – up from the previous 1.2 mmb/d target. Beneath those headlines, however, the details of the new adjustment to the deal were murkier.  The 500,000 b/d cut is, in fact, more of a formalisation of the current production levels within OPEC. It won’t remove additional barrels from the market, but it won’t add them back into global supply either.

Saudi Arabia is, once again, key to this equation. Even with the attacks on the heart of its crude processing facilities in September, Saudi Arabia has been shouldering the extra burden within the deal, making up for errant members that have consistently overshot their quotas. These include Nigeria and Iraq, and crucially Russia. The caveat that the new targets – especially Saudi Arabia’s voluntary portion – will only come into force if all members of the OPEC+ club implement 100% of their pledged cuts underscores the Kingdom’s new, more hardline stance that full compliance is required before it makes additional concessions. Because even with the declines in Venezuela and Iran, Saudi Arabia has trimmed its output to below 10 mmb/d in an attempt to show leadership through example. But its patience is now wearing thin.

But it is those details that are sketchy right now. OPEC states that the new deal formalises current production levels and will make up for Saudi overcompliance by ‘redistributing’ those volumes across other OPEC+ members. But no specifics on that split were given – a worrying sign that more arguments were coming – with the group preferring to meet compliance first before moving on to the fresh cuts.

Full adherence to the targets is tough. But it might get easier. Russia – which has only met its quota 3 months this year, when the Druzhba oil pipeline crisis hit – won a significant concession. Its argument that the only reason it was not hitting its target was due to condensate production, a by-product of its increasing natural gas output, was accepted; the quotas will exclude condensate, and Russian Energy Minister Alexander Novak was optimistic that it could meet its quota of a 300,000 b/d reduction for the first quarter of 2020. And the first quarter of 2020 is crucial, as that is the remaining length of the supply deal. Ahead of the March 31 expiry in 2020, OPEC has agreed to hold an extraordinary general meeting to assess the situation – the point which the deal either ends or is extended.

Underpinning this bet is some sentiment-based optimism from OPEC. The rise and rise of US shale has diluted OPEC’s impact over the past five years, requiring it to make deeper and deeper cuts that were muted by increasing amounts of American crude. But OPEC is betting that the wind will go out of US shale sails next year, hoping that it will allow output within OPEC+ to rise again. But low growth in US shale does not mean no growth. And perhaps for this reason, the price impact on the new OPEC decision has been muted. Despite the club’s attempt to prove that it is still effective, the market simply doesn’t believe the new cut will do much. Crude prices reflect that. Call it cynicism, but the market might have more faith if full compliance was reached and that is exactly what OPEC is striving towards. 

The OPEC+ supply deal: 

  • Reductions of 1.2 mmb/d, as of March 2019
  • A further reduction of 500,000 b/d, formalising October 2019 levels
  • A voluntary cut of 400,000 b/d from Saudi Arabia
  • New cuts will only be formalised once all members comply with their quotas, with full details unavailable
  • Errant members exceeding quotas: Russia, Kazakhstan, Iraq, Nigeria
December, 10 2019