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What can the IMO do make sure that the 0.50% sulphur limit is implemented in an effective, fair and safe manner globally? Discussions at the January session of the IMO’s Sub-Committee on Pollution Prevention and Response (PPR 4) gave us some signals on the thinking and the ideas we may expect to hear more about in the discussions that lie ahead of us.

What emerged from PPR 4 is just the start of this work, as explained in our article “IMO’s work on 0.50% sulphur limit implementation gets underway”.

Under the surface of that outcome are a number of ideas, and opposing views, on the nature of the challenge ahead and how to address it.

The question the International Maritime Organization must try and find and answer to between now and 2020 is how to ensure the transition from the global 3.50% sulphur limit to the 0.50% limit is successful.

There seems to be different schools of thought regarding the challenges ahead.

One the one hand we have “hardliners” who will not accept any excuses or suggestions for smoothing the transition that in any way may fall short of full, strict global implementation and compliance with the new sulphur regime from day one.

On the other hand are those who are concerned about the ability of refiners in their country to provide sufficient low sulphur fuels for both shipping and other sectors in 2020, often the same countries that told the 70th session of the Marine Environment Protection Committee (MEPC 70) that they would rather delay the 0.50% sulphur limit to 2025. They may be looking for some form of regional or country-by-country differentiation in implementation.

In between these two ends of the spectrum are IBIA and other industry organisations represented at IMO, and several countries. IBIA told PPR 4: “We all know what we need to strive for, namely for the entire global fleet to use either low sulphur fuels or technologies that achieve equivalent emissions reductions from the start of 2020.” But IBIA and others told PPR that even if everybody do their utmost to comply in 2020, it seems prudent to put in place contingency measures to deal with potential problem areas. On the one hand, we should avoid penalising ships due to genuine shortages of compliant fuels, and on the other, avoid a situation where it pays to avoid complying because of lacking checks and balances.

The “hardliners” tend to play down any potential problems such the risk of initial regional shortages of compliant fuels, because you can transport products from one region to another. They are also unwilling to acknowledge that the transition may be challenging from a supply standpoint because the IMO study which MEPC 70 based its decision on said availability will be there. They also argue that the transition won’t be sudden because we have three years to prepare and get the products in place. They often highlight that the transition to the 0.10% sulphur limit in emission control areas (ECAs) went well, which should give us confidence that introducing the 0.50% will also be plain sailing, including the introduction of new fuel blends.

The only point everybody seems to agree on is that we need measures in place to make sure ships will be compelled to comply, because without it there is a risk that non-compliance will create significant commercial distortion and an uneven playing field.

Concrete suggestions

During discussions at PPR 4, a few concrete suggestions came up.

Two papers submitted to PPR 4 proposed making it an offense for a ship to carry high sulphur fuel oil (HSFO) in its fuel tanks unless that ship has a certified scrubber or approved exemption.

One suggestion that came up took that idea a step further, namely to implement a ban both on the carriage and sales of HSFO to ships without scrubbers or valid exemptions from the start of 2020, to make the MARPOL Annex VI regulation as simple as possible to implement and enforce. Included in this idea was that suppliers would be required to see evidence that the ship has an approved scrubber or exemption (e.g. check the ship’s IAPP certificate) before being allowed to sell HSFO to any ship.

Some think a HSFO carriage prohibition won’t be necessary, however, because strict enforcement by port state control officers (PSCO), including document checks and fuel sampling, will be enough to prevent ships without scrubbers from carrying and using HSFO.

Another suggestion that came up was that bunker ports can put out official information to IMO ahead of 2020 about whether they will be able to supply compliant fuel or not, so owners can plan their fuel purchasing so as not to be caught out without ability to buy compliant fuel.

One concrete idea put forward by IBIA and IPIECA in papers submitted to PPR 4 was to allow ships awaiting scrubber installations exemption from full compliance with the 0.50% sulphur limit for a limited period. Allowing this, though with strict caveats such as still having to observe the ECA requirements and use low sulphur fuels while in port or close to shore, could alleviate installation bottlenecks and ease demand pressure on 0.50% sulphur fuels at the start of 2020. This proposal was, however, widely objected to, including by shipping industry organisations out of fear it would interfere with a level playing field.

There is one aspect that there is wide agreement on, however, which is the need for developing a draft standard format for reporting non-availability as provided in regulation 18.2.4 of MARPOL Annex VI that may be used to provide evidence if a ship is unable to obtain compliant fuel. This was among the proposals in IBIA’s submissions both to MEPC 70 and PPR 4.

Other suggestions made by IBIA and others, relating to making use of existing IMO tools for reporting and information sharing, were not discussed at PPR 4, and remain in the “idea bank” for now. We can probably expect several other deposits into this “idea bank” at upcoming IMO meetings, but first MEPC 71 has to approve the initial scope outlined at PPR 4. Then the work can begin on identifying and building consensus on the ideas that can help ensuring the world is adequately prepared to successfully implement the 0.50% sulphur limit.

Report by Unni Einemo

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Fossil fuels continue to account for the largest share of U.S. energy

Fossil fuels continue to account for the largest share of energy consumption in the United States. In 2018, about 79% of domestic energy production was from fossil fuels, and 80% of domestic energy consumption originated from fossil fuels.

The U.S. Energy Information Administration (EIA) publishes the U.S. total energy flow diagram to visualize U.S. energy from primary energy supply (production, imports, and stock withdrawals) to disposition (consumption and exports). In this diagram, losses that take place when energy is converted to the secondary forms that are delivered to customers—primarily electricity and gasoline—are allocated to those customers. The result is a visualization that associates the primary energy with customers, even though the amount of energy they purchase is much less.

U.S. energy production by source

Source: U.S. Energy Information Administration, Monthly Energy Review
Note: Natural gas plant liquids (NGPL) denoted at top of left panel in brown.

The share of U.S. total energy production from fossil fuels peaked in 1966 at 93%. Total fossil fuel production has continued to rise, but so have non-fossil fuel sources, mainly renewables like wind and solar energy. As a result, fossil fuels have accounted for close to 80% of U.S. energy production over the past decade. Since 2008, production of crude oil, dry natural gas, and natural gas plant liquids (NGPL) has increased by 12 quadrillion British thermal units (quads), 11 quads, and 3 quads, respectively. These increases have more than offset decreasing coal production, which has fallen 9 quads since its peak in 2008.

U.S. primary energy overview and net imports share of consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Petroleum has the largest share of U.S. energy trade, accounting for 67% of energy exports and 86% of energy imports in 2018. Much of the imported crude oil goes to U.S. refineries and is then exported as petroleum products. Petroleum products accounted for 71% of total U.S. energy exports in 2018.

In 2018, net energy imports reached the lowest level since 1963. U.S. net energy imports as a share of consumption peaked in 2005 when it reached 30%; in 2018, energy net imports fell to only 4% of consumption.

U.S. energy consumption by source and primary energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

The share of U.S. total energy consumption that originated from fossil fuels has fallen from its peak of 94% in 1966 to 80% in 2018. The total amount of fossil fuels consumed in the United States has also fallen from its peak of 86 quads in 2007. Since then, coal consumption decreased by 10 quads and petroleum by 2 quads, more than offsetting a 7 quad increase in natural gas consumption.

EIA previously published articles detailing the energy flows of petroleum, natural gas, coal, and electricity. More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

September, 19 2019
Russia Is Heating Up The Arctic

After a year of securing deals, finalising details and even projecting way beyond the current, Novatek’s Arctic LNG 2 was been given its Final Investment Decision (FID), paving its way for a 2023 start. Led by Russia’s largest independent gas producer, the 19.8 million ton per annum project is also joined by Total, CNPC, CNOOC and the Japan Arctic LNG consortium (consisting of Mitsui & Co and JOGMEC).

The make-up of the project stakeholders is telling. There is Novatek, which aims to catch up with Gazprom as Russia’s largest gas player. Then there is Total, whose savvy deals have propelled it to become the second largest private gas player (behind Shell) through a diversified portfolio. Japan – currently the world’s largest LNG importer – is well represented, while the fast-growing demand market of China is in there as well. Each of the minority players owns a 10% stake but Total also has a 19.4% stake in Novatek, bringing its total economic interest to 21.6%.

The geography of the project is interesting as well. Centred on the Trekhbugornly and Gydanskiy fields, the terminal at Utrenniy and a large-scale liquefaction plant in the remote Gydan Peninsula, passage from this part of Russia’s Arctic is difficult. Which is why Novatek is also partnering with Sovcomflot to build a fleet of 17 icebreaker-class LNG carriers to ferry the super-chilled liquid through the Arctic to Northeast Asia. That’s the Northern Sea Route, the closest direct route to Asia available and it might even get easier. Climate patterns have shifted the Arctic’s ice floes, with new shipping channels opening up from thawing ice in the summer. The journey rivals delivery times from Qatar to Tokyo, or Australia to Shanghai – which explains the high interest from Japanese and Chinese parties. For Total, which has a global presence, Arctic LNG 2 will also be able to deliver cargoes to Europe via transhipment terminals in the Murmansk region.

It also explains why Novatek is already thinking beyond this. Arctic LNG 2 will consist of 3 phases. Train 1 is scheduled for 2023, while Train 2 and Train 3 planned for 2024 and 2026. But Novatek has already made overtures to expand its assets in the Gydan – part of West Siberia’s Yamal-Nenets region. Novatek’s ambitions call for up to 140 mtpa of LNG production in Gydan and Yamal, from its current 16.5 mtpa Yamal LNG and the 19.8 mtpa Arctic LNG 2, though Gazprom has pushed back on Novatek’s lobbying of the Russian government on the issue. However, plans have already been made for at least one more LNG project – oddly titled Arctic LNG 1 – that would focus on the Soletsko-Khanaveyskoye field in the Kara Sea, which has an estimated 2.18 bcm of gas in place.

The net result of this is that Russia will become a more diversified gas player. Besides the Sakhalin II and Yamal LNG projects, Russia primarily sells its gas by pipeline to Europe. But with resistance there increasing – see the furore over the Nord Stream 2 pipeline – Russia needs more options. Geography and weather have always presented challenges to export Siberian gas to Asia and the rest of the world, but Arctic LNG 2 offers a very promising glimpse of a possibly profitable future.

Arctic LNG 2:

  • Stakeholders: Novatek (60%), Total (10%), CNPC (10%), CNOOC (10%), Japan Arctic LNG (10%)
  • Capacity: 19.8 million tons per annum through 3 Trains
  • Location: Gydan Peninsula, West Siberia
September, 18 2019
Natural gas and wind forecast to be fastest growing sources of U.S. electricity generation

In its latest Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) forecasts that natural gas-fired electricity generation in the United States will increase by 6% in 2019 and by 2% in 2020. EIA also forecasts that generation from wind power will increase by 6% in 2019 and by 14% in 2020. These trends vary widely among the regions of the country; growth in natural gas generation is highest in the mid-Atlantic region and growth in wind generation is highest in Texas. EIA expects coal-fired electricity generation to decline nationwide, falling by 15% in 2019 and by 9% in 2020.

The trends in projected generation reflect changes in the mix of generating capacity. In the mid-Atlantic region, which is mostly in the PJM Interconnection transmission area, the electricity industry has added more than 12 gigawatts (GW) of new natural gas-fired generating capacity since the beginning of 2018, an increase of 17%.

This new natural gas capacity in PJM has replaced some coal-fired generating capacity—6 GW of coal-fired generation capacity has been retired in that region since the beginning of 2018. The Oyster Creek nuclear power plant in New Jersey was also retired in 2018, and the Three Mile Island plant in Pennsylvania plans to shut down its last remaining reactor this month.

These changes in capacity contribute to EIA’s forecast that natural gas will fuel 39% of electricity generation in the PJM region in 2020, up from a share of 31% in 2018. In contrast, coal is expected to generate 20% of PJM electricity next year, down from 28% in 2018. In 2010, coal fueled 54% of the region’s electricity generation, and natural gas generated 11%.

PJM annual electric power sector generation

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

Wind power has been the fastest-growing source of electricity in recent years in the Electric Reliability Council of Texas (ERCOT) region that serves most of Texas. Since the beginning of 2018, the industry has added 3 GW of wind generating capacity and plans to add another 7 GW before the end of 2020. These additions would result in an increase of nearly 50% from the 2017 wind capacity level in ERCOT. EIA expects wind to supply 20% of ERCOT total generation in 2019 and 24% in 2020. If realized, wind would match coal’s share of ERCOT's electricity generation this year and exceed it in 2020.

ERCOT annual electric power sector generation

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

Natural gas-fired generation in ERCOT has fluctuated in recent years in response to changes in the cost of the fuel. EIA forecasts the Henry Hub natural gas price will fall by 21% in 2019, which contributes to EIA’s expectation that ERCOT’s natural gas generation share will rise from 45% in 2018 to 47% this year. Although EIA forecasts next year’s natural gas prices to remain relatively flat in 2020, the large increase in renewable generating capacity is expected to reduce the region’s 2020 natural gas generation share to 41%.

September, 18 2019