NrgEdge Editor

Sharing content and articles for users
Last Updated: April 10, 2019
1 view
Business Trends
image

U.S. residential electricity price

Forecast Highlights

Global liquid fuels

  • For the 2019 summer driving season that 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. EIA’s forecast is discussed in its Summer Fuels Outlook. The lower forecast gasoline prices primarily reflect EIA’s expectation of lower crude oil prices in 2019. For all of 2019, EIA expects U.S. regular gasoline retail prices to average $2.60/gal and gasoline retail prices for all grades to average $2.71/gal, which would result in the average U.S. household spending about $100 (4%) less on motor fuel in 2019 compared with 2018.
  • Brent crude oil spot prices averaged $66 per barrel (b) in March, up $2/b from February 2019. Brent prices for the first quarter of 2019 averaged $63/b, which is $4/b lower than the same period in 2018. Despite lower crude oil prices than last year, Brent prices in March were $9/b higher than in December 2018, marking the largest December-to-March price increase since December 2011 to March 2012. EIA forecasts Brent spot prices will average $65/b in 2019 and $62/b in 2020, compared with an average of $71/b in 2018. EIA expects that West Texas Intermediate (WTI) crude oil prices will average $8/b lower than Brent prices in the first half of 2019 before the discount gradually falls to $4/b in late-2019 and through 2020.
  • EIA estimates that U.S. crude oil production averaged 12.1 million barrels per day (b/d) in March, up 0.3 million b/d from the February average. EIA forecasts that U.S. crude oil production will average 12.4 million b/d in 2019 and 13.1 million b/d in 2020, with most of the growth coming from the Permian region of Texas and New MexicoWest Texas Intermediate (WTI) crude oil price


World liquid fuels production and consumption balance


Natural gas

  • The Henry Hub natural gas spot price averaged $2.95/million British thermal units (MMBtu) in March, up 26 cents/MMBtu from February. Prices increased as a result of colder-than-normal temperatures across much of the United States, which increased the use of natural gas for space heating. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019 and in 2020. EIA expects Henry Hub natural gas spot prices will average $2.82/MMBtu in 2019, down 33 cents/MMBtu from 2018. The forecasted 2020 Henry Hub spot price is $2.77/MMBtu.
  • EIA forecasts that 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 natural gas production will continue to grow in 2020 to an average of 92.5 Bcf/d.
  • EIA estimates that natural gas inventories ended March at 1.2 trillion cubic feet (Tcf), which would be 17% lower than levels from a year earlier and 30% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections will outpace the previous five-year average during the April-through-October injection season and that inventories will reach 3.7 Tcf at the end of October, which would be 13% higher than October 2018 levels but 1% lower than the five-year average.


  • U.S. natural gas prices


  • U.S. residential electricity price


  • West Texas Intermediate (WTI) crude oil price


Electricity, coal, renewables, and emissions

  • EIA expects the average U.S. residential customer will use an average of 1,026 kilowatt hours (kWh) of electricity per month during the summer cooling season that runs from June through August, 2019, about 5% less than the same period last year. EIA uses the National Oceanic and Atmospheric Administration’s weather forecast, which indicates that temperatures will be cooler than last summer in all regions of the United States. The cooler forecast temperatures contribute to the lower expected electricity use.
  • EIA forecasts that U.S. residential electricity prices will average 13.4 cents/kWh during the summer cooling season, about 2% higher than last summer. The higher forecast prices primarily reflect higher actual generation fuel costs from 2018 that affect retail rates with a time lag, as well as rising electric transmission and distribution costs.
  • EIA forecasts that all renewable fuels, including wind, solar, and hydroelectric generation, will produce 18% of U.S. electricity in 2019, and almost 20% in 2020. EIA expects that wind generation will surpass hydroelectric generation to become the leading source of renewable electricity in both years.
  • EIA estimates that U.S. coal production decreased by 19 million short tons (MMst) (2%) in 2018, totaling 756 MMst. EIA expects that coal production will continue to fall in the forecast as both domestic consumption and exports, which reached a five-year high in 2018, are forecast to decline. In the electric power sector, which accounts for more than 90% of U.S. coal consumption, more than 7 gigawatts of coal-fired generation is scheduled to retire by the end of 2020. EIA forecasts that coal production will total 684 MMst in 2019 (down by 9% from 2018) and 640 MMst in 2020 (down by 6% from 2019).
  • After rising by 2.7% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.6% in 2019 and by 1.0% in 2020. EIA expects emissions to fall in 2019 and in 2020 as forecasted temperatures return to near normal after a warm summer and cold winter in 2018, and because the share of electricity generated from natural gas and renewables is forecast to increase while the share generated from coal, which produces more CO2 emissions, is forecast to decrease. Energy-related CO2 emissions are sensitive to weather, economic growth, energy prices, and fuel mix.

STEO natural gas renewable energy electricity coal energy emission liquid fuels forecast
3
1 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

The World’s Largest Natural Gas Discovery Since 2005

At the start of February, a major new find was jointly announced by the two largest emirates within the UAE: the oil-rich Abu Dhabi and the ambitious Dubai. Between them, they literally made the world’s largest natural gas discovery since 2005. Located at the border between the two sheikdoms, the Jebel Ali field is estimated to contain some 80 trillion scf of natural gas, the largest global find since the Galkynysh field in Turkmenistan.

Stretching over 5,000 square km, an exploration campaign by Abu Dhabi involving over 10 wells confirmed the enormous discovery in early January 2020. The shallow nature of the onshore reserves should make it easier to extract gas at lower costs, hastening the time-to-market. At current estimated figures, Jebel Ali would be the fourth-largest gas field in the Middle East, behind Qatar’s North Field, Iran’s South Pars and Abu Dhabi’s own Bab field.

The politics of the UAE can be complicated; each emirate is essentially self-governing with federal oversight, which is dominated by Abu Dhabi and Dubai (which always hold the President and Prime Minister roles, according to convention). This essentially means that each emirate has grew quite independently. Fujairah, for example, developed into a bunkering port, while Sharjah went into industry and manufacturing. Dubai is globally famous for its titanic real estate projects, pursued finance, services and media, while Abu Dhabi, the largest and most blessed of all with hydrocarbon resources, turned into an energy powerhouse. Oil & gas wealth in the UAE is mainly in Abu Dhabi; so while the Jebel Ali discovery is a welcome addition for Abu Dhabi, it is a game changer for Dubai, which imports most of its energy needs.

Speculation has raised that possibility that the Jebel Ali field could vault the UAE into gas self-sufficiency, because even Abu Dhabi imports gas. The UAE has a stated goal to be gas independent by 2030. On paper, that’s possible. Abu Dhabi’s ADNOC has agreed to develop the field with Dubai’s gas supplier, the Dubai Supply Authority (DUSUP), with the entire supply will be channel to DUSUP for use in Dubai. Jebel Ali could begin producing gas by 2023, and will likely be distributed domestically through pipeline. The enormous reserves could supply the entire UAE’s gas demand for nearly 30 years, assuming optimal recovery conditions. However, in practice, self-sufficiency might take longer to achieve.

Dubai and indeed, Abu Dhabi are currently reliant on Qatar for their gas supply. An existing sales agreement that expires in 2032 sees Qatar pipe 2 bcf/d of gas to the UAE through Abu Dhabi. The problem is that these neighbours are erstwhile friends. A division in the Middle East between the pro-Saudi Arabia and pro-Iran blocs has caused a rift. Led by Saudi Arabia, several Persian Gulf states  including the UAE implemented a diplomatic and trade blockade on Qatar, isolating it. The blockade, slightly weakened, still continues today. Even now, planes flying into Qatar have to make strange manoeuvres when approaching to avoid encroaching on Saudi and UAE airspace. However, the gas supply arrangement remains in place.

And this is where the Jebel Ali discovery could come in handy. Qatar is already on track to be self-sufficient in gas terms by 2025, but will probably honour the Qatar deal until expiration. Dubai has been increasingly reliant on LNG  through an FSRU for power generation, but has attempted over the years to kick-start a number of coal or solar-power projects. Jebel Ali won’t kick the addiction, but it could definitely reduce Dubai’s reliance on Qatari gas.

Jebel Ali wasn’t the only recent gas discovery made in the UAE. Further north, the Sharjah National Oil Corp and Italy’s Eni announced a new onshore gas and condensate discovery. Though tiny in comparison to Jebel Ali, some 50 mscf/d of lean gas and condensate. The cumulative effects of these discoveries could make gas self-sufficiency a reality sooner. At this point, the UAE consumes some 7.4 bcf gas per day, while marketed production is some 6.2 bcf/d. An ambitious plan to develop Abu Dhabi’s large gas fields was the rationale behind naming the 2030 self-sufficiency deadline. With the discovery of Jebel Ali, that can now be brought forward by a couple of years at least. And there might even be some left over to be exported as LNG

The UAE Major Gas Projects:

  • Estimated reserves: 273 tcf of conventional gas, 160 tcf of unconventional gas (Abu Dhabi)
  • Ghasha ultra-sour gas field (Abu Dhabi) – 1.5 bcf, by 2025
  • Shah sour gas field (Abu Dhabi) – 1.5 bcf/d

February, 23 2020
Your Weekly Update: 17 - 21 February 2020

Market Watch   

Headline crude prices for the week beginning 17 February 2020 – Brent: US$53/b; WTI: US$49/b

  • As the Covid-19 pandemic seems to be coming increasingly under control, crude oil prices are recovering some ground as the market moves into speculative mode given the availability of cheap crude cargoes
  • Case in point, while the fear was of widespread demand destruction in China, a sudden buying spree by Chinese independent teapot refineries – attracted by cheap spot cargoes – surprised the market, being a sign that Chinese private refiners are anticipating a rebound in demand sooner rather than later
  • Despite this, the pandemic is still recalibrating Chinese energy demand in a dramatic way, with reports of four LNG tanker bound for northern China from Oman and Qatar diverted as CNOOC invoked force majeure on its contracts
  • China’s pain is also India’s gain, with so-called ‘distressed cargoes’ originally intended for China now offered to India at attractive terms from all over the world, including grades from the Caspian Sea to Latin America and West Africa
  • Based on the situation in China, the IEA is forecasting the first annual decline in quarterly global oil demand for the first time in over a decade, and dragging overall 2020 growth down by 30% to 825,000 b/d; the EIA followed suit as well, cutting its Brent price forecast for 2020 from US$64.83 to US$61.25
  • China and key Asian hubs impacted by the virus like Hong Kong and Singapore have pledged to provide extra fiscal stimulus to counteract the impact of the pandemic, possibly setting the stage for a rebound in Q2 2020
  • Saudi Arabia’s attempt to cajole the OPEC+ club into extending its supply cuts until June 2020 through an emergency February meeting has faded, with Russia being the main holdout
  • Amid the turmoil in the markets, the US active rig count remained unchanged for the week, adding two oil sites but losing gas and miscellaneous sites for a total of 790
  • Oil prices gained over the week as the Covid-19 pandemic looks to be contained; Brent should trade in a higher US$57-59/b range and WTI at US$43-55/b


Headlines of the week

Upstream

  • Saudi Arabia and Kuwait have officially restarted production from their shared Wafra field in the Neutral after five years of halted output
  • Despite being hampered by quarterly waivers that are subject to renewals by the US government, Chevron has ramped up production at its Petropiar crude upgrader plant in Venezuela to 130,000 b/d after being closed for most of 2019
  • Canada’s Alberta province’s plan to ease its crude glut through rail shipments has hit a snag, as protestors blocked train lines and the provincial government ordered trains to reduce speeds after a major derailment and fire
  • Tullow Oil reports that it has received approval from Ghana to flare gas ‘when necessary’ from its offshore fields, which should help the beleaguered company support production levels after a set of disappointing results for 2019
  • Somalia has passed a new petroleum bill into law, with the aim of setting up a regulatory framework to attract foreign upstream investment; Somalia currently does not produce any oil but estimates suggest significant reserves
  • As Uganda prepares to start producing oil for the first time, distribution and transport infrastructure remain an issue, with the state recently tapping a Chinese lender to build three roads to connect to its western oilfields
  • After a challenging few years of scandals and a subsequent refocusing on upstream, Petrobras has now hit a new upstream production record, with the ramp-up in pre-salt basins contributing to 3.025 mmboe/d in Q4 2019
  • CNOOC has commenced production at the offshore Bozhong 34-9 field in the Bohai Sea, with peak output expected at 22,500 b/d of crude by 2022

Midstream/Downstream

  • The Covid-19 Wuhan outbreak has claimed a few more refinery scalps, with ChemChina shutting down its 100 kb/d Zhenghe refinery in Shandong and reducing processing at its Changyi and Huaxing refineries by 10%; Hengli Petrochemical has cut utilisation rates at its new 400 kb/d Dalian refinery by some 17% as well, as petchem demand dries up
  • The 120,000 b/d Azzawiya Oil Refining Company refinery in Libya has been forced to halt all operations, as a prolonged conflict in the country has dried up the availability of crude for export or local refining
  • Egypt has given the go-ahead for a US$2.5 billion, 65 kb/d oil refinery in the Upper Egypt region, focusing on hydrocracking mazut – heavy, low quality fuel oil typically used for power generation – into high-value fuels
  • The Bangladesh Petroleum Corp has awarded a tender to supply some 1.06 million tons of gasoil, jet fuel, fuel oil and gasoline to Unipec and Vitol
  • Vietnam’s Nghi Son refining has offered a cargo of gasoil for export for the first time – an indication of slowing domestic demand from the Covid-19 outbreak that is hitting most major East and Southeast Asian economies

Natural Gas/LNG

  • NextDecade Corp’s US$15 billion, 26 million tons per annum Rio Grande LNG facility in Texas has been cleared for LNG exports by the US DoE
  • Portugal’s Sines port is being eyed by US energy companies as a strategic landing point for US LNG exports to Europe, as American LNG exporters race to lock down customers amid a supply glut that could last for years
  • Shell has acquired a 50% stake in Ecopetrol’s Fuerte Sur, Purple Angel and COL-5 gas blocks located in Colombia’s Caribbean deepwater region
February, 21 2020
This Week in Petroleum

Forecast growth in demand for U.S. petroleum and other liquids is not driven by transportation and not supplied by refineries

The U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO) forecasts that in 2021, U.S. consumption (as measured by product supplied) of total petroleum and other liquid fuels will average 20.71 million barrels per day (b/d), surpassing the 2007 pre-recession level of 20.68 million b/d. However, the drivers of this consumption growth have changed. Since the 2007–09 recession, U.S. consumption growth has shifted toward liquid fuels that are used primarily outside the transportation sector and are supplied mostly from non-refinery sources. Despite this shift away from domestic demand for refinery-produced fuels, U.S. refinery runs have increased, and the excess products have been exported, greatly contributing to the United States becoming a net exporter of petroleum in September 2019. EIA expects these trends to continue for at least the next 10 years.

Hydrocarbon gas liquids (HGL) have been the main driver of U.S. petroleum and other liquids demand growth since 2007 (Figure 1). U.S. production and consumption of HGLs—a group of products that include ethane, propane, normal butane and isobutane, natural gasoline, and refinery olefins—have risen with increased natural gas production and demand from an expanding petrochemical sector. As a result, EIA forecasts U.S. HGL consumption will be 1.27 million b/d more in 2021 than in 2007, and will average 3.45 million b/d.

Figure 1. Forecast change in U.S. consumption from 2007 to 2021

With the exception of jet fuel, EIA expects less U.S. consumption of refinery-produced products in 2021 than in 2007. Since 2007, increases in U.S. vehicle miles traveled, which normally increases total motor gasoline consumption, have been countered to some extent by increases in vehicle fuel efficiency. In addition, although U.S. total motor gasoline consumption exceeded 2007 levels for the first time in 2016, increased blending of ethanol into finished motor gasoline has displaced some of the petroleum-based, or refinery-produced, portion of gasoline consumption. Therefore, EIA forecasts 570,000 b/d less consumption of refinery-produced gasoline in the United States in 2021 than in 2007, while ethanol will be 0.5 million b/d higher. Ethanol is almost exclusively produced at non-petroleum refinery sites.

Some HGLs can be produced by both refineries and natural gas processing plants. Natural gas plant liquids (NGPLs)—a subset of HGLs that includes ethane, propane, normal butanes and isobutanes, and natural gasoline—can be extracted from natural gas production streams or produced at refineries that process crude oil. However, as U.S. natural gas production increased from 55.3 billion cubic feet per day (Bcf/d) in 2007 to 98.9 Bcf/d in 2019, the amount of HGLs extracted from natural gas production increased from 1.78 million b/d in 2007 to 4.83 million b/d in 2019. EIA expects HGL production from natural gas processing plants to continue to increase to 5.47 million b/d in 2021. Meanwhile, refinery HGL production has been flat at about 600,000 b/d (Figure 2).

Figure 2. U.S. hydrocarbon gas liquids production by source

Although HGLs have several different end uses, such as propane for space heating and normal butane for blending with motor gasoline, most of the growth in consumption stems from the use of HGLs as feedstock for petrochemical processes. The large increase in U.S. production of HGLs, and the resulting low prices, led to large investments in U.S. infrastructure to extract and transport HGLs to market, as well as investments in petrochemical facilities to consume it. Many of these facilities consume ethane, and to a lesser degree propane and normal butane, as feedstocks to produce intermediate building blocks for plastics, resins, and other materials with nonenergy uses. EIA forecasts that U.S. ethane consumption will reach 1.96 million b/d in 2021, up from 743,000 b/d in 2007, which represents 96% of the increase in U.S. HGL consumption between 2007 and 2021.

Removing HGL and ethanol consumption from the total demand for U.S. petroleum and other liquids indicates that EIA’s 2021 forecast U.S. demand for principally refinery-produced products is about 16.31 million b/d, on par with the 1997 level (Figure 3).

Figure 3. U.S. total petroleum and other liquids demand

Despite domestic demand shifting away from traditionally refinery-produced products, U.S. refinery capacity has increased 1.7 million b/d between 2007 and 2019. U.S. refineries have adapted to falling domestic demand for certain products, such as residual fuel, by investing in downstream coking capacity to upgrade it into more valuable products. More importantly, international demand for refinery-produced products has increased since 2007, allowing U.S. refineries to increase runs and utilization beyond what the domestic market demanded to supply products to export markets. As a result, the United States became a net exporter on an annual basis of distillate and residual fuel in 2008, of jet fuel in 2011, and of motor gasoline in 2016.

Similarly, demand for HGLs outside of the United States has increased and caused U.S exports of HGLs to increase from 70,000 b/d in 2007 to 2.07 million b/d in November 2019. Between 2013 and 2016, exports of HGLs were the largest contributor to the increase in U.S. exports of petroleum products. U.S. exports of HGLs are mostly of propane and ethane to markets in Asia and Europe, where they are also displacing refinery-produced naphtha as a petrochemical feedstock.

EIA projects that these trends of increasing U.S. production of HGLs, increasing domestic consumption of HGLs, and increasing exports of HGLs will continue beyond 2021. EIA’s Annual Energy Outlook 2020 (AEO2020), released in January, shows projections for further growth in HGL production at natural gas processing plants from 4.91 million b/d in 2019 to a peak of 6.58 million b/d in 2029 and then slowly decline to 6.17 million b/d by 2050. Domestic consumption of HGLs will also increase, driven by continued petrochemical demand for feedstock, which rises from about 3.14 million b/d in 2019 to more than 4.0 million b/d in 2029. Meanwhile, in the AEO2020 Reference case, U.S. consumption of motor gasoline declines until 2042, distillate consumption declines until 2040, and residual fuel consumption continues declining out to 2050.

U.S. average regular gasoline prices rise, diesel prices decline

The U.S. average regular gasoline retail price increased nearly 1 cent from the previous week to $2.43 per gallon on February 17, 11 cents higher than the same time last year. The Midwest price rose nearly 5 cents to $2.31 per gallon. The Rocky Mountain price fell more than 3 cents to $2.47 per gallon, the West Coast price fell 1 cent to $3.14 per gallon, the East Coast price fell nearly 1 cent to $2.36 per gallon, and the Gulf Coast price declined by less than 1 cent to $2.08 per gallon.

The U.S. average diesel fuel price fell 2 cents from the previous week to $2.89 per gallon on February 17, 12 cents lower than a year ago. The Rocky Mountain price fell nearly 4 cents to $2.86 per gallon, the East Coast price fell more than 2 cents to $2.94 per gallon, the Midwest and Gulf Coast prices each fell nearly 2 cents to $2.76 per gallon and $2.66 per gallon, respectively, and the West Coast price fell more than 1 cent to $3.47 per gallon.

Residential heating oil prices increase, propane prices decrease

As of February 17, 2020, residential heating oil prices averaged more than $2.91 per gallon, almost 1 cent per gallon above last week’s price but more than 31 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged $1.80 per gallon, more than 5 cents per gallon above last week’s price but 34 cents per gallon lower than a year ago.

Residential propane prices averaged more than $1.98 per gallon, less than 1 cent per gallon below last week’s price and nearly 45 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.56 per gallon, more than 1 cent per gallon higher than last week’s price but almost 27 cents per gallon below last year’s price.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 3.0 million barrels last week to 74.3 million barrels as of February 14, 2020, 18.4 million barrels (32.9%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories decreased by 1.1 million barrels, 1.0 million barrels, 0.6 million barrels, and 0.4 million barrels, respectively. Propylene non-fuel-use inventories represented 7.5% of total propane/propylene inventories.

February, 21 2020