Short-Term Energy Outlook
December 12, 2017 Release
Global liquid fuels
North Sea Brent crude oil spot prices averaged $63 per barrel (b) in November, an increase of $5/b from the average in October. EIA forecasts Brent spot prices to average $57/b in 2018, up from an average of $54/b in 2017.
West Texas Intermediate (WTI) crude oil prices are forecast to average $4/b lower than Brent prices in 2018. After averaging $2/b lower than Brent prices through the first eight months of 2017, WTI prices averaged $6/b lower than Brent prices from September through November.
NYMEX WTI contract values for March 2018 delivery traded during the five-day period ending December 7, 2017, suggest that a range of $48/b to $68/b encompasses the market expectation for March WTI prices at the 95% confidence level.
· EIA estimates that U.S. crude oil production averaged 9.7 million barrels per day (b/d) in November, up 360,000 b/d from the October level. Most of the increase was in the Gulf of Mexico, where production was 290,000 b/d higher than in October. Higher production in November reflected oil production platforms returning to operation after being shut in response to Hurricane Nate. EIA forecasts total U.S. crude oil production to average 9.2 million b/d for all of 2017 and 10.0 million b/d in 2018, which would mark the highest annual average production, surpassing the previous record of 9.6 million b/d set in 1970.
· U.S. regular gasoline retail prices averaged $2.56 per gallon (gal) in November, an increase of nearly 6 cents/gal from the average in October. The increase in November primarily reflected increasing crude oil prices. EIA forecasts the U.S. regular gasoline retail price will average $2.59/gal in December, 34 cents/gal higher than at the same time last year. EIA forecasts that U.S. regular gasoline retail prices will average $2.51/gal in 2018.
· U.S. dry natural gas production is forecast to average 73.5 billion cubic feet per day (Bcf/d) in 2017, a 0.7 Bcf/d increase from the 2016 level. EIA forecasts that natural gas production in 2018 will be 6.1 Bcf/d higher than the 2017 level.
· In November, the U.S. benchmark Henry Hub natural gas spot price averaged $3.01 per million British thermal units (MMBtu), up nearly 14 cents/MMBtu from October. Expected growth in natural gas exports and domestic natural gas consumption in 2018 contribute to an increase in EIA’s forecast Henry Hub natural gas spot price from an annual average of $3.01/MMBtu in 2017 to $3.12/MMBtu in 2018. NYMEX contract values for March 2018 delivery that traded during the five-day period ending December 7, 2017, suggest that a range of $1.98/MMBtu to $4.27/MMBtu encompasses the market expectation for March Henry Hub natural gas prices at the 95% confidence level.
Electricity, coal, renewables, and emissions
· EIA expects the share of total U.S. utility-scale electricity generation from natural gas will average about 32% in 2017, down from 34% in 2016 as a result of higher natural gas fuel costs and increased generation from renewable energy sources. EIA projects the 2017 share of generation from coal will average 30%, about the same as last year. The forecast 2018 generation shares for natural gas and coal remain relatively unchanged from 2017, averaging 32% and 31%, respectively. Generation from renewable energy sources other than hydropower grows from about 8% in 2016 to a forecast share of nearly 10% in 2018. Nuclear power’s forecast share of total electricity generation averages about 20% in both 2017 and 2018, similar to its 2016 level.
· Estimated U.S. coal production for the first 11 months of 2017 is 719 million short tons (MMst), 54 MMst (8%) higher than production for the same period in 2016. Annual production is expected to be 791 MMst in 2017, falling to 771 MMst in 2018 because of lower exports and no growth in coal consumption.
· U.S. coal exports for the first three quarters of 2017 were 69 MMst, 68% (28 MMst) higher than exports for the same period in 2016. This total for the first three quarters of 2017 is already 14% (8 MMst) higher than total annual coal exports in 2016. EIA expects that exports will total 89 MMst in 2017 and 74 MMst in 2018.
· U.S. wind electricity generating capacity at the end of 2016 totaled 81 gigawatts (GW). EIA expects wind capacity additions in the forecast to raise total wind capacity to 88 GW by the end of 2017 and to 96 GW by the end of 2018.
· Total U.S. utility-scale solar electricity generating capacity at the end of 2016 was 22 GW. EIA expects solar capacity additions will bring total utility-scale solar capacity to 27 GW by the end of 2017 and to 30 GW by the end of 2018.
· After declining by 1.7% in 2016, U.S. energy-related carbon dioxide (CO2) emissions are projected to decrease by 0.8% in 2017 and then to increase by 1.8% in 2018. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, and energy prices.
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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:
Headline crude prices for the week beginning 17 February 2020 – Brent: US$53/b; WTI: US$49/b
Headlines of the week
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.
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).
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).
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.