January 1st 2020 won’t just be the start of a new year or a new decade; it is a significant date for the international shipping industry as the most radical new rules for shipping fuels in decades are implemented. From New Year’s Day onwards, a 0.5% sulphur cap (or 500ppm) in fuel will be imposed globally, part of the International Maritime Organization’s aim to reduce greenhouse gas emissions from ships by 50% through 2050. Adopted in October 2016, the cap was already in discussion and debate long before it was codified. So there has been plenty of time to prepare. The question now is: is the shipping industry prepared for the new change?
But first, a little history. The first enforcement of global shipping emissions came through the IMO – a United Nations agency – in May 2005, when Annex VI of the MARPOL environmental convention came into effect. Earlier annexes of MARPOL dealt with other polluting factors, but Annex VI specifically addressed air pollution – including Nitrogen Oxides and Sulphur Oxides. Prior to this, shipping fuels and emissions were largely unregulated globally (although national and regional standards did apply). In 2008, the IMO set the global upper limit for sulphur in shipping fuels at 3.5% (or 3500 ppm), which came into effect 2012; the new 2020 cap is another great leap – possibly the greatest leap so far.
There are major challenges in meeting this new rules. For decades, ships plying international waters ran on heavy, high sulphur fuel oil. This itself was a change from the previous paradigm, where ships ran on coal. Why did the switch happen? Simple economics. As the world’s oil refining industries developed post-World War II, the focus was on producing high-value fuels such as gasoline, gasoil and jet fuel for the transportation revolution. If the crude oil processed was light and sweet, there wouldn’t be much left after refining. But if the crude was heavier and more sour, then there was a lot left over. This heavy fuel oil was embraced by the shipping industry as a more efficient (operationally and economically) fuel for ships. What was an unwanted by-product now had value. It was a boon for refiners, as they did not have to bother refining the HFO further. And it was a boon for shippers, a ready source of cheap fuel.
Heavy fuel oil – some with sulphur levels exceeding 15000 ppm – was used by shippers worldwide, especially in international waters where national emission standards would not apply. The IMO MARPOL Annex VI has changed that. There are two avenues to meeting the new 2020 standard –invest in an exhaust gas cleaning system (also known as a scrubber) that would allow the ship to continue to burn HFO, or switch to cleaner fuels – principally marine gasoil (MGO) or low-sulphur fuel oil (LSFO). The former seems less attractive – a Lloyd’s survey suggests only 19% of shipowners would go for scrubbers – and the latter has some restrictions… both technical (compatibility with engine systems) and logistic (requiring new blending and storage facilities). There is a third category – running on LNG – but that applies mainly to new ships. The vast majority will have to buy and burn compliant marine fuels.
Several questions are still up in the air. LSFO and MGO currently carry a US$250/ton premium over HFO, a major increase that shippers will have to pass on to their clients – using a tool known as the Bunker Adjustment Factor (BAF). Refiners – particularly those near key ports such as Singapore, Shanghai and Amsterdam – have already invested in capacity to produce more MGO and LSFO, so supply isn’t that much of an issue, outside of pockets of unavailability in smaller ports. Asian refineries, in fact, are already running a surplus of IMO 2020-compliant LSFO. But some countries are showing resistance, including Indonesia that opted out of IMO 2020 for domestic marine usage, citing the age of its fleet. However, in existing Emission Control Areas like the Baltic Sea, North Sea and the Caribbean Sea, an ultra-low sulfur limit of 0.1% (100ppm) applies – presaging a future where a similar limit will apply globally through an upcoming IMO resolution. But, and this is crucial to the success of the new policy, the IMO has not set out concrete fines and sanctions for non-compliance, leaving enforcement and penalties to the individual port authorities – a delegation of responsibility that could dilute the effectiveness of the mandate.
Adjusting to the new IMO 2020 rule will involve an intricate matching of supply and demand. And money. Money is at the heart of this issue, as refiners, shippers and ports invest money into meeting the new requirements. Shipping is about to get a lot cleaner, and more expensive. At stake, however, is the health of the planet itself. And it’s hard to put a price on achieving that, no matter how much money needs to be spent.
IMO 2020 Marine Fuel/Engine Regulations:
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Pioneering technology expert tells ADIPEC Energy Dialogue up to 80 per cent of plant shutdowns could be mitigated through combination of advanced electrification, automation and digitalisation technologies
Greater use of renewables in power management processes offers oil and gas companies opportunities to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects
Abu Dhabi, UAE – XX August 2020 – Leveraging the synergies created by the convergence of electrification, automation and digitalisation, can create significant cost savings for oil and gas companies when making both operational and capital investment decisions, according to Dr Peter Terwiesch, President of Industrial Automation at ABB, a Swiss-Swedish multinational company, operating mainly in robotics, power, heavy electrical equipment, and automation technology areas.
Participating in the latest ADIPEC Energy Dialogue, Dr Terwiesch said up to 80 per cent of energy industry plant shutdowns, caused by human error, or rotating machinery or power outages, could be mitigated through a combination of electrification, automation and digitalisation.
“Savings are clearly possible not only on the operation side but also, using the same synergies between dimensions, you can bring down the cost schedule and risk of capital investment, especially in a time when making projects work economically is harder,” explained Dr Terwiesch.
A pioneering technology leader, who works closely with utility, industry, transportation and infrastructure customers, Dr Terwiesch said despite the increasing investment by oil and gas companies in renewables and the growing use of renewables to generate electricity, both for individual and industrial uses, hydrocarbons will continue to have an important role in creating energy, in the short to medium term.
“If you look at the energy density constraints, clearly electricity is gaining share but electricity is not the source of energy; it is a conduit of energy. The energy has to come from somewhere and that can be hydrocarbons, or nuclear, or renewables.” he said.
Nevertheless, he added, the greater use of renewables to generate electricity offers oil and gas companies the option of integrating a higher share of renewables into power management processes to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects.
The ADIPEC Energy Dialogue is a series of online thought leadership events created by dmg events, organisers of the annual Abu Dhabi International Exhibition and Conference. Featuring key stakeholders and decision-makers in the oil and gas industry, the dialogues focus on how the industry is evolving and transforming in response to the rapidly changing energy market.
With this year’s in person ADIPEC exhibition and conference postponed to November 2021, the ADIPEC Energy Dialogue, along with insightful webinars, podcasts and on line panels continue to connect the oil and gas industry, with the challenges and opportunities shaping energy markets in the run up to, and following, a planned three-day live stream virtual ADIPEC conference taking place from November 9-11.
An industry first of its kind, the online conference will bring together energy leaders, ministers and global oil and gas CEOs to assess the collective measures the industry needs to put in place to fast-track recovery, post COVID-19.
To watch the full ADIPEC Energy Dialogue series go to: https://www.youtube.com/watch?v=QZzUd32n3_s&t=6s
Utility-scale battery storage systems are increasingly being installed in the United States. In 2010, the United States had seven operational battery storage systems, which accounted for 59 megawatts (MW) of power capacity (the maximum amount of power output a battery can provide in any instant) and 21 megawatthours (MWh) of energy capacity (the total amount of energy that can be stored or discharged by a battery). By the end of 2018, the United States had 125 operational battery storage systems, providing a total of 869 MW of installed power capacity and 1,236 MWh of energy capacity.
Battery storage systems store electricity produced by generators or pulled directly from the electrical grid, and they redistribute the power later as needed. These systems have a wide variety of applications, including integrating renewables into the grid, peak shaving, frequency regulation, and providing backup power.
Most utility-scale battery storage capacity is installed in regions covered by independent system operators (ISOs) or regional transmission organizations (RTOs). Historically, most battery systems are in the PJM Interconnection (PJM), which manages the power grid in 13 eastern and Midwestern states as well as the District of Columbia, and in the California Independent System Operator (CAISO). Together, PJM and CAISO accounted for 55% of the total battery storage power capacity built between 2010 and 2018. However, in 2018, more than 58% (130 MW) of new storage power capacity additions, representing 69% (337 MWh) of energy capacity additions, were installed in states outside of those areas.
In 2018, many regions outside of CAISO and PJM began adding greater amounts of battery storage capacity to their power grids, including Alaska and Hawaii, the Electric Reliability Council of Texas (ERCOT), and the Midcontinent Independent System Operator (MISO). Many of the additions were the result of procurement requirements, financial incentives, and long-term planning mechanisms that promote the use of energy storage in the respective states. Alaska and Hawaii, which have isolated power grids, are expanding battery storage capacity to increase grid reliability and reduce dependence on expensive fossil fuel imports.
Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report
Note: The cost range represents cost data elements from the 25th to 75th percentiles for each year of reported cost data.
Average costs per unit of energy capacity decreased 61% between 2015 and 2017, dropping from $2,153 per kilowatthour (kWh) to $834 per kWh. The large decrease in cost makes battery storage more economical, helping accelerate capacity growth. Affordable battery storage also plays an important role in the continued integration of storage with intermittent renewable electricity sources such as wind and solar.
Additional information on these topics is available in the U.S. Energy Information Administration’s (EIA) recently updated Battery Storage in the United States: An Update on Market Trends. This report explores trends in battery storage capacity additions and describes the current state of the market, including information on applications, cost, market and policy drivers, and future project developments.