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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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In 2018, the United States consumed more energy than ever before

U.S. total energy consumption

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

Primary energy consumption in the United States reached a record high of 101.3 quadrillion British thermal units (Btu) in 2018, up 4% from 2017 and 0.3% above the previous record set in 2007. The increase in 2018 was the largest increase in energy consumption, in both absolute and percentage terms, since 2010.

Consumption of fossil fuels—petroleum, natural gas, and coal—grew by 4% in 2018 and accounted for 80% of U.S. total energy consumption. Natural gas consumption reached a record high, rising by 10% from 2017. This increase in natural gas, along with relatively smaller increases in the consumption of petroleum fuels, renewable energy, and nuclear electric power, more than offset a 4% decline in coal consumption.

U.S. total energy consumption

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

Petroleum consumption in the United States increased to 20.5 million barrels per day (b/d), or 37 quadrillion Btu in 2018, up nearly 500,000 b/d from 2017 and the highest level since 2007. Growth was driven primarily by increased use in the industrial sector, which grew by about 200,000 b/d in 2018. The transportation sector grew by about 140,000 b/d in 2018 as a result of increased demand for fuels such as petroleum diesel and jet fuel.

Natural gas consumption in the United States reached a record high 83.1 billion cubic feet/day (Bcf/d), the equivalent of 31 quadrillion Btu, in 2018. Natural gas use rose across all sectors in 2018, primarily driven by weather-related factors that increased demand for space heating during the winter and for air conditioning during the summer. As more natural gas-fired power plants came online and existing natural gas-fired power plants were used more often, natural gas consumption in the electric power sector increased 15% from 2017 levels to 29.1 Bcf/d. Natural gas consumption also grew in the residential, commercial, and industrial sectors in 2018, increasing 13%, 10%, and 4% compared with 2017 levels, respectively.

Coal consumption in the United States fell to 688 million short tons (13 quadrillion Btu) in 2018, the fifth consecutive year of decline. Almost all of the reduction came from the electric power sector, which fell 4% from 2017 levels. Coal-fired power plants continued to be displaced by newer, more efficient natural gas and renewable power generation sources. In 2018, 12.9 gigawatts (GW) of coal-fired capacity were retired, while 14.6 GW of net natural gas-fired capacity were added.

U.S. fossil fuel energy consumption by sector

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

Renewable energy consumption in the United States reached a record high 11.5 quadrillion Btu in 2018, rising 3% from 2017, largely driven by the addition of new wind and solar power plants. Wind electricity consumption increased by 8% while solar consumption rose 22%. Biomass consumption, primarily in the form of transportation fuels such as fuel ethanol and biodiesel, accounted for 45% of all renewable consumption in 2018, up 1% from 2017 levels. Increases in wind, solar, and biomass consumption were partially offset by a 3% decrease in hydroelectricity consumption.

U.S. energy consumption of selected fuels

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

Nuclear consumption in the United States increased less than 1% compared with 2017 levels but still set a record for electricity generation in 2018. The number of total operable nuclear generating units decreased to 98 in September 2018 when the Oyster Creek Nuclear Generating Station in New Jersey was retired. Annual average nuclear capacity factors, which reflect the use of power plants, were slightly higher at 92.6% in 2018 compared with 92.2% in 2017.

More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

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A New Frontier for LNG Pricing and Contracts

How’s this for a first? As the world’s demand for LNG continues to grow, the world’s largest LNG supplier (Shell) has inked an innovative new deal with one of the world’s largest LNG buyers (Tokyo Gas), including a coal pricing formula link for the first time in a large-scale LNG contract. It’s a notable change in an industry that has long depended on pricing gas off crude, but could this be a sign of new things to come?

Both parties have named the deal an ‘innovative solution’, with Tokyo Gas hailing it as a ‘further diversification of price indexation’ and Shell calling it a ‘tailored solutions including flexible contract terms under a variety of pricing indices.’ Beneath the rhetoric, the actual nuts and bolts is slightly more mundane. The pricing formula link to coal indexation will only be used for part of the supply, with the remainder priced off the conventional oil & gas-linked indexation ie. Brent and Henry Hub pricing. This makes sense, since Tokyo Gas will be sourcing LNG from Shell’s global portfolio – which includes upcoming projects in Canada and the US Gulf Coast. Neither party provided the split of volumes under each pricing method, meaning that the coal-linked portion could be small, acting as a hedge.

However, it is likely that the push for this came from Tokyo Gas. As one of the world’s largest LNG buyers, Tokyo Gas has been at the forefront of redefining the strict traditions of LNG contracts. Reading between the lines, this deal most likely does not include any destination restriction clauses, a change that Tokyo Gas has been particularly pushing for. With the trajectory for Brent crude prices uncertain – owing to a difficult-to-predict balance between OPEC+ and US shale – creating a third link in the pricing formula might be a good move. Particularly since in Japan, LNG faces off directly with coal in power generation. With the general retreat from nuclear power in the country, the coal-LNG battle will intensify.

What does this mean for the rest of the industry? Could coal-linked contracts become the norm? The industry has been discussing new innovations in LNG contracts at the recent LNG2019 conference in Shanghai, while the influx of new American LNG players hungry to seal deals has unleashed a new sense of flexibility. But will there be takers?

I am not a pricing expert but the answer is maybe. While Tokyo Gas predominantly uses natural gas as its power generation fuel (hence the name), it is competing with other players using cheaper coal-based generation. So in Japan, LNG and coal are direct competitors. This is also true in South Korea and much of Southeast Asia. In the two rising Asian LNG powerhouses, however, the situation is different. In China – on track to become the world’s largest LNG buyer in the next two decades – LNG is rarely used in power generation, consumed instead by residential heating. In India – where LNG imports are also rising sharply – LNG is primarily aimed at petrochemicals and fertiliser. LNG based power generation in China and India could see a surge, of course, but that will take plenty of infrastructure, and time, to build. It is far more likely that their contracts will be based off existing LNG or natural gas benchmarks, several of which are being developed in Asia alone.

If it takes off  the coal-link LNG formula is likely to remain a Asian-based development. But with the huge volumes demanded by countries in this region, that’s still a very big niche. Enough perhaps for the innovation to slowly gain traction elsewhere, next stop -  Europe?

The Shell-Tokyo Gas Deal:

Contract – April 2020-March 2030 (10 Years)

Volume – 500,000 metric tons per year

Source – Shell global portfolio

Pricing – Formula based on coal and oil & gas-linked indexes

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