The sulfur content of transportation fuels has been declining for many years as a result of 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 operational decisions.
Bunker fuel—the fuel typically used in large ocean-going vessels—is a mixture of petroleum-based oils. Residual oil—the long-chain hydrocarbons remaining after lighter and shorter hydrocarbon fractions such as gasoline and diesel have been separated from crude oil—currently makes up the largest component of bunker fuel. The sulfur content of crude oil tends to be more concentrated in heavier hydrocarbons, 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 United Nations agency that sets standards for marine fuels, decided in October to move forward with a plan to reduce the maximum allowable levels of sulfur and other pollutants 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, which limited the maximum sulfur content of fuels to 0.1% by weight starting in July 2015.
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. These limits will present 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 is to use low-sulfur intermediate refinery feedstocks in bunker blends.
A second challenge for refiners is deciding 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 to do so are not currently attractive to refiners. An alternative strategy is to build or expand refinery units that take heavy hydrocarbons and upgrade them into lighter, more valuable products. 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 ships to continue to use 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 nonpetroleum-based fuels. Some newer ships can use liquefied natural gas (LNG) rather than petroleum-based products. However, the infrastructure to support the 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 higher costs as the sulfur content in marine fuels decreases and as the role of distillate in the bunker fuel market increases. An example of the price difference between fuels can be observed at the Amsterdam-Rotterdam-Antwerp refining and trading hub in Northwest Europe. In 2016, prices for low-sulfur gasoil, a type of distillate, have averaged over $ 20 per barrel more than high-sulfur fuel oil (residual oil for use as a fuel) to date. Fuel blends used to meet the new IMO regulations are likely to be priced somewhere between these two fuels
Principal contributor: Mason Hamilton
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One of the many report launches at COP22 was the 2016 Global Status of CCS (Carbon Capture and Storage), released by GCCSI (Global Carbon Capture and Storage Institute) on November 15th. The report identifies 15 large-scale CCS projects in operation around the world, with a CO2 capture capacity of close to 30 million tonnes per annum (Mtpa).
A further three large-scale projects, all in the US, are poised to become operational, bringing the number of operational projects to 18 by early 2017 (with a CO2 capture capacity of 35 Mtpa). As projects in Australia and Canada come on-line during 2017, the number of large-scale operational CCS projects is expected to increase to 21 by the end of 2017, with a CO2 capture capacity of approximately 40 Mtpa. This compares with less than 10 operational large-scale CCS projects in 2010.
Encouraging as this is, it is not enough. The report notes that the current level of CCS deployment does not go anywhere near what is required from CCS to meet the Paris ‘well below’ 2°C climate target.
One chart of particular interest is on page 13 of the report and compares spending over the last decade on CCS vs. clean energy. For CCS the total is $ 20 billion, compared with $ 2.5 trillion for clean energy investment. But in many instances, the justification for clean energy investment is claimed to be for low emissions and consequent climate benefits, rather than simply for the energy generated. If that is the case, how do these two approaches compare on a pure climate basis?
CCS is a technology that is entered into almost entirely for climate reasons. While some carbon dioxide is used for Enhanced Oil Recovery (EOR) and various niche applications, for the most part this is a technology designed to prevent carbon dioxide from entering atmosphere when fossil fuels are used, instead returning it to the geosphere. By contrast, a technology such as solar PV is designed to produce electricity, which may then displace a certain fossil fuel usage that might have been used to generate the same amount of electricity. However, its effectiveness for climate mitigation purposes depends on the nature of the displacement; it is quite possible that the displaced fuel is used elsewhere or consumed later, which may negate some or all of the benefit claimed.
Returning to the chart and the report, by the end of 2017 some 40 Mtpa of carbon dioxide will be captured and stored. Also by 2017 there will be some 300 GW of solar PV in the world. The latter has had at least an order of magnitude more fiscal support than that offered to CCS, and according to GCCSI clean energy in total has had over two orders of magnitude more investment than CCS. Let’s assume from the chart that a third of the Total Clean Energy is solar, so $ 800 billion.
To assess the climate benefit of solar PV, let us use a solar company figure; the First Solar project, Desert Sunlight Solar Farm, is 550 MW and according to the project website displaces some 300,000 tonnes of carbon dioxide annually. On that basis 300 GW of solar is displacing 163 Mtpa of carbon dioxide, compared with the 40 Mtpa that CCS is achieving.
So for ~$ 30 billion ($ 20 billion in the period 2006-2015 and perhaps ~$ 10 billion prior to 2006), CCS is achieving a quarter the climate benefit as ~$ 800 billion of solar, on an investment basis. Of course, this is not the complete story as the CCS incurs an annual operating cost and the Solar PV provides electricity, but there is a factor of nearly seven here in terms of carbon dioxide benefit in favour of the CCS.
CCS has not yet had the same opportunity as solar PV for cost reductions, given the small number of installations, although results from facilities such as the Shell Quest plant in Canada have already indicated that savings are there. If this is the case that factor may well increase.
The GCCSI report highlights the effectiveness of CCS when faced with the issue of emissions mitigation, which is what the climate issue is really all about. Simply building out renewable energy capacity with the hope of permanently displacing fossil fuel use may not be a cost effective approach when climate is the single objective. Of course, we don’t live in a world of single objectives, but nevertheless the calculation above demonstrates that we need to give CCS a much greater opportunity to flourish and do the job for which it is ideally positioned; permanently removing carbon dioxide.
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U.S. pipeline exports of natural gas continued to grow in 2016, and they have doubled since 2009. Almost all of this growth is attributable to increasing exports to Mexico, which have accounted for more than half of all U.S. natural gas exports since April 2015. In August, the United States exported 4.2 billion cubic feet per day (Bcf/d) of natural gas to Mexico via pipelines. U.S. daily pipeline exports to Mexico through August 2016 are at a yearly average of 3.6 Bcf/d, 25% above the year-ago level and 85% above the five-year (2011–15) average level.
In 2015, Mexico’s energy ministry (SENER) announced a five-year plan to significantly expand the country’s natural gas pipeline network to accommodate higher levels of natural gas imports from the United States. These imports would help meet increasing power demand, offset declining domestic natural gas production, reduce reliance on LNG imports, and create new markets for natural gas in currently supply-constrained regions. The plan proposed 12 pipeline additions, increasing the existing network capacity and adding more than 3,200 miles of new pipeline through Mexico.
According to SENER’s July 2016 update, contracts have been awarded for 7 of the 12 pipeline projects. The largest and most expensive of the awarded projects is the Sur de Texas-Tuxpan pipeline, which aims to supply the Mexican states of Tamaulipas and Veracruz with natural gas from southern Texas via an underwater route through the Gulf of Mexico. The pipeline will extend nearly 500 miles and provide a total transport capacity of 2.6 Bcf/d.
Growth in Mexico’s domestic electricity market has largely driven the country’s increasing natural gas usage. Because of the availability and affordability of U.S. pipeline natural gas, Mexico is meeting its growing electricity demand with generation from new natural gas-fired plants. U.S. natural gas exports to Mexico are expected to continue to grow in the short term, and SENER forecasts a widening gap between domestic production and demand through the end of the decade. Mexican imports of natural gas continue to outpace most projections. The 4.1 Bcf/d exported in August 2016 matched the level originally forecasted in 2013 to be reached in 2018.
However, uncertainty in Mexican demand growth, particularly from the power generation sector as natural gas-fired capacity competes with renewables and nuclear generation, may slow the increase in Mexico’s natural gas imports, leading to lower pipeline capacity utilization. Domestic natural gas production may also rebound and reduce the need for pipeline imports from the United States.
Principal contributor: Kirstin Berndt, Mike Mobilia
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