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Last Updated: November 24, 2016
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Tighter marine fuel sulfur limits will spark changes by both refiners and vessel operators.

The sulfur content of transportation fuels has been declining for many years due to increasingly stringent regulations. In the United States, federal and state regulations limit the amount of sulfur present in motor gasoline, diesel fuel, and heating oil. New international regulations limiting sulfur in fuels for ocean-going vessels, set to take effect in 2020, have further implications for both refiners and vessel operators at a time of high uncertainty in future crude oil prices, which will be a major factor in their decisions.

Bunker fuelthe fuel typically used in large ocean-going vesselsis a mixture of petroleum-based oils. Residual oilthe long-chain hydrocarbons remaining after lighter and shorter hydrocarbon fractions such as gasoline and diesel have been separated from crude oilcurrently makes up the largest component of bunker fuel. The sulfur content of crude oil tends to be more concentrated in heavier hydrocarbon molecules, with heavier petroleum products such as residual oil having higher sulfur content than lighter ones like gasoline and diesel.

The International Maritime Organization (IMO), the 171-member state United Nations agency that sets standards for marine fuels, decided in October to move forward with a plan to reduce the maximum amount of sulfur and other pollutants present in marine fuels used on the open seas from 3.5% by weight to 0.5% by weight by 2020. This decision follows several other marine fuel regulations limiting sulfur content, such as the implementation of Emissions Control Area (ECA) requirements in coastal waters and specific sea-lanes in North America and Europe, where the maximum sulfur content of fuels was limited to 0.1% by weight starting in July 2015 (Figure 1).

Additionally, the state of California and the European Union have regulations on the sulfur content of marine fuels, and the types of fuel used when ships are at dock, waiting to dock, or are maneuvering within port. For example, a vessel approaching the port of San Francisco may have to change its fuel mix twice: once when going from the open seas higher-sulfur fuel of mostly residual oil, to an ECA compliant lower-sulfur fuel mix, and again to a marine diesel fuel compliant with California's ocean-going vessel regulations for use within ports (Figure 2).

The IMO sulfur limits that take effect in 2020 will affect the fuel used in the open seas, the largest portion of the approximately 3.9 million barrels per day of global marine fuel use, according to the International Energy Agency, presenting several challenges for both refiners and shippers.

The first challenge for refiners is to increase the supply of lower-sulfur blendstocks to the bunker fuel market. Refiners have several potential paths. One approach is to divert more low sulfur distillates into the bunker fuel market. Another option would be to use low sulfur intermediate refinery feedstocks in bunker blends. In both cases, care is required to assure that new fuels continue to meet specifications for use in marine engines.
A second challenge for refiners is what to do with the high sulfur residual oil that can no longer be blended into bunker fuel. Adding capacity to desulfurize residual oil is one option, but the economics do not currently appear to be attractive. An alternative strategy is to build or expand refinery units that take heavy hydrocarbons, such as residual oil, and upgrade them into lighter, more valuable products, but this would require large investments. In either of these cases, refineries would be faced with investments and costs that are acceptable only if there is certainty of future demand from the shipping industry.

Vessel operators also have several choices for compliance with the new IMO sulfur limits. For example, IMO regulations allow for the installation of scrubbers, which remove pollutants from ships exhaust, allowing them to continue to use higher-sulfur fuels. Some ship owners that operate primarily in coastal areas, such as cruise lines and ferries, opted to install scrubbers on their vessels as the new ECA regulations came into force. The possibility of widespread scrubber installations, which would allow for continued use of higher sulfur residual oils, could make refiners hesitant about making large investments to build refining units capable of upgrading the residual oils.

Ships also have the option of switching to new lower sulfur blends or to non-petroleum based fuels. Some newer ships and some currently being built have engines that would allow them to use liquefied natural gas (LNG) rather than petroleum-based products. However, the infrastructure to support use of LNG as a shipping fuel is currently limited in both scale and availability.
Vessel operators and shippers will also likely be faced with the higher costs as the sulfur content in marine fuels decreases and the role of distillate in the bunker fuel market increases. An example of the price difference between fuels can be observed at the refining and trading hub in Northwest Europe, known as the ARA, collectively the cities Amsterdam and Rotterdam, in the Netherlands and Antwerp, in Belgium. Prices for low sulfur gasoil, a type of distillate, in the ARA has averaged over $20 per barrel more than high sulfur fuel oil (residual oil for use as a fuel) to date in 2016. Fuel blends used to meet the new IMO regulations are likely to price somewhere in between these two fuels (Figure 3).

U.S. average regular gasoline and diesel retail prices decline
The U.S. average regular gasoline retail price dropped three cents from the previous week to $2.16 per gallon on November 21, up six cents from the same time last year. The Gulf Coast price fell six cents to $1.92 per gallon, while the West Coast, Rocky Mountain, and East Coast prices each fell five cents to $2.59 per gallon, $2.19 per gallon, and $2.17 per gallon, respectively. The Midwest price rose two cents to $2.01 per gallon.

The U.S. average diesel fuel price dropped two cents to $2.42 per gallon, down two cents from the same time last year. The Rocky Mountain price fell four cents to $2.46 per gallon, while the West Coast and Midwest prices each fell three cents to $2.73 per gallon and $2.36 per gallon, respectively. The Gulf Coast price dipped two cents to $2.30 per gallon, and the East Coast price fell a penny to $2.44 per gallon.

Propane inventories gain U.S. propane stocks increased by 1.8 million barrels last week to 102.7 million barrels as of November 18, 2016, 3.5 million barrels (3.3%) lower than a year ago. Gulf Coast and Rocky Mountain/West Coast inventories increased by 1.7 million barrels and 0.1 million barrels, respectively, while East Coast and Midwest inventories remained virtually unchanged. Propylene non-fuel-use inventories represented 4.0% of total propane inventories.

Residential heating oil price unchanged while residential propane price increases as of November 21, 2016, residential heating oil prices averaged around $2.38 per gallon, virtually unchanged from last week and less than one cent per gallon higher than last year at this time. The average wholesale heating oil price is $1.55 per gallon, nearly eight cents per gallon higher than last week and 13 cents per gallon more than a year ago.

Residential propane prices averaged nearly $2.06 per gallon, one cent per gallon more than last week and almost 11 cents per gallon more than one year ago. Wholesale propane prices averaged $0.62 per gallon, about the same price as last week but 13 cents per gallon more than last year's price.

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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