Even as new commitments and frameworks to reduce greenhouse gas emissions are rolled out by the world’s largest economies, one sector in particular is the source of the greatest uncertainty in future emissions pathways: transport fuels. It is the only major sector for which emissions continue to increase in every region of the world, and the lack of compelling, cost-effective, and scalable alternatives means that the fuels now in use—chiefly diesel and gasoline—must be slowly decarbonized in the decades ahead if climate goals are to be achieved.
Several governments around the world are exploring a pioneering new greenhouse gas (GHG) policy—emissions intensity standards—to address this challenge. This policy can help discourage the use of relatively high-carbon fuels and promote the development of low-carbon alternatives without placing restrictions on the total volume of fuel sold. But as the long fight over the European Union’s ambitious Fuel Quality Directive(FQD) shows, it also faces significant headwinds.
The FQD has largely been caught up in a narrative that pits European environmental regulators against Canadian oil sands. But the struggle over its implementation reveals a much larger insight: as governments anticipate future constraints on greenhouse gas emissions in the decades ahead, they are largely unprepared to deal with the paradigm shift taking place in the transport fuels sector, as unconventional fuels with opaque climate footprints begin to play a larger and larger role.With oil and its alternatives evolving, emissions intensity standards are important tools for decarbonizing transport fuels. Before they can succeed in the long run, however, a more nuanced understanding of their benefits, limitations, and geopolitical implications is required.
A Challenging Imperative
Any regulation seeking to temper the growth of transport emissions is complicated by the highly interconnected nature of the global fuel market. Trade flows of petroleum and petroleum products—with an annual wealth transfer on the order of $2.3 trillion from importers to exporters—are of great consequence to the global economy.1 Yet such regulation is essential if an unacceptably harmful level of climate change is to be avoided; petroleum matters far too much.
In terms of the world’s most prevalent greenhouse gas, carbon dioxide (CO2), 35 percent of global CO2 emissions from fuel combustion can be attributed to oil. A major driver behind this is the combustion of oil-based road transport fuels, primarily diesel and gasoline. Oil is expected to account for approximately 87 percent of all global transport fuels over the next two decades, with road transport alone accounting for more than 70 percent of global oil consumption.
In the EU, road transport accounts for approximately 20 percent of total GHG emissions. Crucially, this is the only major sector in which GHG emissions are increasing: transport’s GHG footprint has risen by approximately 36 percent since 1990 while that of all other sectors declined by 15 percent over the same period.
But the entire oil value chain, when assessed comprehensively, carries an even larger emissions footprint. Those statistics do not include GHG emissions other than carbon dioxide, nor do they account for emissions associated with the extraction, transport, and refining of transport fuels themselves. Fully accounting for these emissions suggests that the petroleum sector may be responsible for a far higher share of total global GHG emissions.2
For policymakers, a comprehensive approach to simultaneously enhancing energy security, reducing oil dependence, and decarbonizing the transport sector involves three interlinked efforts: enhancing vehicle efficiency, reducing vehicle use, and decarbonizing the overall fuel mix. Vehicle efficiency has seen success through national-level regulations, and reduced vehicle use can be achieved through prudent planning and investments at all levels of government. But the fuel mix has thus far befuddled policymakers.
How can the fuel mix of a single country or region be made more climate-friendly in a mostly globalized fuel market? Does the domestic prohibition of inexpensive but high-emissions fuels simply shift them offshore, to less stringently regulated jurisdictions? Is it possible to craft fuel emissions intensity standards in a way that does not breach a country’s free trade commitments under the World Trade Organization?
To avoid tangling with the complexities of the global oil market, some policies such as renewable fuel mandates have sought to promote alternative fuels by requiring an arbitrary quantity to be produced and/or blended into transport fuels each year. Others have required a certain proportion of all transport fuels sold in a given year to be nonpetroleum fuels, such as bioethanol or biodiesel.
Commonly, such policies are driven by a complex set of objectives and vested interests, the transparency of which varies. For example, ambitious renewable fuel mandates are often introduced in countries that already possess significant domestic agricultural resources, or whose agribusiness interests have amassed political clout.
To date, only a single major country—Brazil—has succeeded in replacing petroleum as the dominant fuel used in transport. This was achieved only after three decades of uncommonly consistent policy support for sugarcane ethanol. And while Brazil’s transport sector is relatively decarbonized as compared with its petroleum-based counterparts, it has not necessarily insulated itself from price volatility as ethanol increasingly becomes a globally traded, politically sensitive commodity.
Similar attempts by the United States or the EU to “bet the farm” on one petroleum alternative like biofuels through strictly defined renewable fuel mandates are problematic. They risk economic inefficiency by foreclosing other avenues to reducing emissions (including greater efficiency in the transport and refining of oil, or the electrification of the transport sector). They also risk driving up food prices with little or no climate benefit, depending on the crop used as a feedstock.
In the power sector, carbon taxes are an appealing and effective way to encourage a shift away from coal to cleaner energy sources and to reduce overall energy demand. But direct carbon taxation is more problematic in the transport sector, given the fact that a much higher carbon price—likely politically unacceptable—would be required to meaningfully decrease fuel use and encourage cleaner fuels. As a result, many scholars maintain that emissions intensity standards for transport fuels remain the most pragmatic and promising policy alternative.
Fuel Emission Intensity Standards in Concept
Emissions intensity standards seek to reduce the GHG intensity of transport fuels and foster alternative fuels without necessarily establishing a cap on the total volume of transport fuel emissions. They instead set an emissions intensity target for the lifecycle greenhouse gas emissions per unit of transport fuel energy supplied in a given market. Targets are usually expressed in terms of grams of carbon dioxide equivalent per mega-joule of energy supplied (gCO2e/MJ). The targets are often articulated as a percentage reduction against the emissions intensity of a baseline year. These policies then assign default emissions intensity values to various fuels depending on their particular production pathway—that is, what feedstock they were produced from and the process used to produce them.
These standards are hybrid instruments that neither explicitly price carbon emissions (as with a carbon tax) nor explicitly limit the total amount of permissible emissions (as with a cap-and-trade system). Instead, they combine an implicit carbon tax with an implicit output subsidy.
The implicit tax derives from the fact that by employing different default lifecycle emissions values for different fuel pathways, pathways with higher emissions values will see their prices drop in the fuel market. Similarly, pathways with lower emissions values will enjoy market premiums.
The implicit production subsidy derives from the fact that, because the policy focuses on the intensity of the fuel mix, rather than setting ceilings or floors on the quantity of various fuels sold, it could encourage the consumption of more, not less, total fuel than would otherwise be consumed in order to comply with the standard. As more fossil fuels are sold, more alternative fuel sales become necessary to dilute the carbon intensity of the overall mix, driving up the volume of total fuel sales in a given period.
Fuel Emissions Intensity Standards in Practice
An emissions intensity standard for transport fuel was first pioneered by California, where then governor Arnold Schwarzenegger signed the Low Carbon Fuel Standard (LCFS) into law in 2007.
The California standard aims to reduce the emissions intensity of the state’s transport fuel mix by 10 percent between 2010 and 2020. Under the regime, all fuels are theoretically assessed on a lifecycle basis so that every aspect of their value chain—from extracting/growing the feedstock through to final combustion of the fuel in a vehicle engine—is accounted for in the carbon intensity values assigned to individual fuel pathways.
While petroleum-based fuels such as conventional gasoline and diesel are clearly the most impacted, the LCFS encompasses all imaginable pathways of transport fuels, from those produced from ethanol or vegetable oils to those produced from coal, methane, or even animal tallow. The California standard is notably also the first such regulation to account for emissions associated with indirect land-use change—in other words, the emissions that result when biofuel crops replace food crops and push food crop cultivation elsewhere.
To allow for flexibility in meeting the mandate, California’s LCFS includes provisions for the trading of credits. Fuel suppliers generate credits when the carbon intensity of sold fuel falls below a certain benchmark, and they generate deficits when sold fuel displays a carbon intensity value above the benchmark. In contrast to cap-and-trade systems for reducing carbon emissions, no credits are sold or distributed by regulators; they arise solely from market activity. Those with credits can use them to comply with current reduction requirements, hold them for future compliance periods, or sell them to other parties. This trading activity provides a price discovery mechanism that allows for an implicit price on carbon to emerge from the standard.3
California’s impact on international fuel markets has been modest thus far. But its approach has been emulated by other jurisdictions. Oregon and Washington are in the early stages of developing similar measures, while British Columbia’s Renewable and Low Carbon Fuel Requirement Regulation is already in place, the second measure in the world (after California) to include provisions for the direct regulation of fossil fuel carbon intensity. Most significantly, California’s LCFS has provided the template for the only supranational manifestation of a fuel emissions intensity standard to date: the EU Fuel Quality Directive.
The European Experience
Few know the difficulty of the transport sector’s climate policy challenge better than the European Union, whose ambitious but beleaguered plan was well intentioned though inadequately conceived.
The EU’s FQD, published in 2009, is aimed at reducing the climate impacts arising from road transport fuels. But its path to implementation has been marked by a long history of delays and setbacks after continued resistance from foreign governments and domestic industry. The result, at least for the time being, is a system that sets tough standards for emissions intensity but does not explicitly favor the use of comparatively cleaner oils.
Under the FQD, suppliers are required to reduce the carbon intensity of transport fuel supplied in the EU market by at least 6 percent by the end of 2020, as measured against a 2010 baseline.
Beginning on January 1, 2011, fuel suppliers were to start reporting the volume and type of fuel or energy supplied to the EU market, indicating its origin, production process, and lifecycle GHG emissions. Few if any did so, however, because the reporting procedures were not in place.
Article 7a of the FQD was to lay down a methodology for this reporting as well as specific default GHG intensity values for various fuels or fuel pathways. But the details of that measure were left to future policy development—and quickly became the subject of much debate.
In 2012, the European Commission put forth a proposal for article 7a that penalized transport fuels produced from certain unconventional feedstocks (coal, gas, oil sands, and oil shale) by assigning them higher default GHG intensity values (see figure 1).
The 2012 proposal prompted concerns and complaints from an array of interested parties, who questioned the transparency of the policy design process, the feasibility and costs of compliance for the EU refining industry, and the narrow selection of only a handful of crude types—while the significant inherent diversity in the emissions intensities of various conventional crude oils was neglected. There were also objections from U.S. business groups, who said that the measure constitutes an unnecessary barrier to international trade.
The most visible partisan in the debate has been the government of Canada, which has complained that the directive unfairly singles out fuels made from Canadian oil sands for punitive regulatory treatment on the basis of their associated GHG emissions while giving a free ride to other GHG-intensive oils. Canada has employed a number of different tools in pressing its case, including extensive lobbying of both the EU and individual member state governments, studies commissioned to analyze perceived flaws in the FQD, and even the threat of a trade war at the WTO.
Finally, in October 2014—more than five years after the FQD’s conception—the European Commission announced a revised article 7a that would no longer reward and penalize individual fuel suppliers on the basis of their particular fuel mix. Instead, the directive will assign all suppliers a single, EU-wide average emissions intensity of all fuel supplied each year, regardless of the particular fuel feedstocks and production pathways associated with an individual supplier.
This apparent concession means that the FQD will not include an explicit mechanism to favor the usage of conventional oil over high-GHG unconventional oils such as the extra-heavy oil deposits found in Canada and Venezuela. The most recent formulation of the directive also lacks a mechanism to discern between various conventional oils, which display a surprisingly wide spread of emissions intensities, in some cases even higher than those of many unconventional oils. Operational factors such as the flaring or venting of methane—a greenhouse gas far more potent than carbon dioxide—are often key elements driving the emissions intensity of high-GHG conventional oils. Yet these factors are poorly understood and characterized in current policy, whether in the EU or anywhere else in the world.
While the binding requirement of at least a 6 percent emissions intensity reduction by 2020 endures, it remains to be seen what specific economic incentive individual refineries and other fuel suppliers will have to integrate this goal into their day-to-day business decisions. This looming free-rider challenge will likely persist until the EU addresses it in a more comprehensive fashion.
On the positive side, the EU will require fuel suppliers to report each import’s Market Crude Oil Name (MCON)—an identifier for the oil’s field-level origin, from a list of some 600 commonly traded crudes—bringing the FQD into greater alignment with similar practices in California.
There are signs that the European Commission was at one point seriously considering the assignment of explicit carbon intensities to each of these MCONs, in what would have made for a far more robust and stringent policy. A leaked May 2014 document from the European Commission displayed a compilation of upstream (from the point of extraction to the refinery gate) carbon intensity values for various crude oils, along with their corresponding sulfur content and API gravity (lower API gravity oils are heavier and more difficult to refine, while higher API gravity oils are lighter and easier to refine).
The commission ultimately chose not to use this data in its final implementation guidelines, and a closer analysis reveals why this outcome was all but inevitable: there are not only large gaps in available data, but an individual oil’s ranking is also likely to vary depending on which aspects of its lifecycle emissions—from upstream to refining to final combustion—are explicitly modeled and which are simply given a default value.
Of the 408 crude oils for which API gravity and sulfur content information was available, carbon intensity values were available to the EU for only 166 (see figure 2). It would be difficult for the EU to fill these gaps through interpolation, as there appears to be surprisingly little correlation between key oil characteristics such as API gravity and sulfur content on the one hand, and upstream carbon intensity values on the other. This is particularly true for heavy oils. Put differently, though oils that are especially heavy and sulfurous are often assumed to be associated with higher lifecycle emissions, this is not necessarily true in all instances. The variation is significant enough to warn against making assumptions without explicit modeling results.
Carnegie’s Oil Initiative has also established that upstream carbon intensities may not always be effective predictors of full lifecycle GHG intensities. The commission will require more comprehensive emissions analysis if the specificity, credibility, and robustness of FQD implementation is to be improved in future years.
In another potential warning sign for the FQD’s future implementation struggles, the directive’s reporting requirement also does not appear to apply to imported petroleum products. This policy choice may incentivize the offshoring of refining activity and complicate pursuit of broader European environmental and energy security objectives.
The Next Steps
Even with the European Commission’s newest implementing regulations, the dust is far from settled on the Fuel Quality Directive. On December 3, 2014, the European Parliament’s environment committee voted to reject the commission’s newest implementing measure. The rejection must now be considered by the broader European Parliament. If the parliament votes against the implementing measure, it will be returned to the commission with a request that it be redrafted to better align with the original commission proposal. With a view toward the protracted fight ahead, those interested in ensuring the success and spread of emissions intensity standards in the fuel sector should pursue the following:
Reframe the Debate
The debate about fuel quality standards should focus on oils, not governments. The notion that the EU’s emissions intensity standards are trade weapons targeted at Canada’s oil sands is both incorrect and counterproductive.
Individual oils and processes can vary greatly in terms of their emissions intensity, and the least climate intensive Canadian oil sands operators may prove to be more climate friendly than poorly managed heavy oil operations in California, Canada, Mexico, Venezuela, or elsewhere. And in China, Iraq, Nigeria, North Dakota, and Russia, where the flaring or venting of methane is prevalent, oil sands may not necessarily be more climate intensive than poorly managed lighter oils.
Focus on Data
More data on the changing characteristics and trade patterns of petroleum-based fuels should be collected and made publicly available. Robust data is the foundation of well-designed policy and allow for existing regulations to be empirically tested to judge whether they are achieving their stated objective.
In the EU, allocating ring-fenced funds to enhance data collection in the fuel sector will help to address the fears of many fuel suppliers that the new policy will lead to exorbitant new costs associated with tracking key data along the supply chain of a fuel. Institutionalizing data-sharing activities with other jurisdictions will also help in tracking whether emissions leakage is occurring due to high-carbon fuels being arbitraged away from regulated markets and reintroduced into markets with less stringent or nonexistent fuels regulation.
Integrate New Modeling Approaches
Each fuel emissions intensity regulation endorses a lifecycle emissions analysis model that then becomes the de facto arbiter of default values for that particular scheme. These include the OPGEE upstream oil emissions model developed by Stanford University, the PRELIM refining model developed by the University of Calgary, the comprehensive GREET transport fuel lifecycle model developed by Argonne National Laboratory, and the GHGenius lifecycle model currently used in Canada. To provide more robust insights into the most likely climate impacts of various oils, new projects such as Carnegie’s Oil Initiative are seeking to integrate different models with different strengths (in this case OPGEE and PRELIM).
Both existing and emerging fuel standards should remain open to integrating the findings of this work into future policy.
Address Quantitative Modeling Uncertainty
Each lifecycle analysis model offers advantages and disadvantages driven by its provenance and focus, and each can also often arrive at different values for the same fuel. Moreover, the best estimate of the average emissions intensity of two fuels might be the same while the corresponding probability distributions may be radically different.
More nuanced approaches are needed that offer greater scientific fidelity than the point estimates that are currently favored. This could include the weighted mean of a fuel’s emissions probability distribution across several models or other methods that better communicate uncertainty. Additionally, the use of conservative estimates of intensity values could be an effective way of incentivizing industry to provide more detailed and transparent data over time.
Engage With the World Trade Organization
In light of growing accusations that negotiations over new bilateral trade deals such as the Canada-EU Comprehensive Economic and Trade Agreement may have played a role in the weakening of the Fuel Quality Directive, more attention should be paid to the interaction between fuel standards and the multilateral trading system.
Governments with an interest in fuel carbon intensity standards should ensure collaboration between environmental and trade policy communities to establish a shared conceptual framework for how these measures, if eventually brought to the WTO as part of a trade dispute, might be interpreted and adjudicated. Although such measures appear to be technical regulations and not border carbon tariff adjustments, this has never been formally established in the multilateral trade system, and best-practice design principles for such measures do not exist.
A working group that links the WTO’s committee on technical barriers to trade with institutions such as the OECD and the International Energy Agency, as well as representatives from Canada, the European Union, and the United States, could bring more clarity to ambiguities over the interaction between fuel standards and the trading system, avoiding protracted and counterproductive disputes in the future.
Conclusion
Addressing the climate impacts of fuel use is not a trivial task, and it is complicated by the role that oil plays in the global economy and in the energy security paradigm of many governments.
But while climate change is growing in salience as a key policy mandate, particularly in the developed world, translating this mandate into meaningful policy frameworks is proving more challenging than many had expected. Many key countries continue to espouse a desire to address global warming while simultaneously maximizing oil extraction. As long as the dominance of oil in the global economy prevails, these two seemingly contradictory goals must be reconciled.
Emissions intensity standards are powerful tools for managing this process, but sober thinking and more effort is needed to overcome the challenges they have faced so far.
Notes
1 Wealth transfer here is defined as the value of 2013 aggregate oil imports (54.66 million barrels per day) multiplied by the 2013 average price for the Brent crude oil benchmark ($108/barrel). All data are drawn from the BP Statistical Review of World Energy 2014. Note that this represents only a first degree wealth transfer before the subsequent flow of petrodollars to consumption (goods and services) or investment (assets) is taken into account.
2 Carnegie’s Oil Initiative has begun to measure the GHG emissions associated with the entire oil value chain for individual global oils. This value chain includes exploration and field development, oil production, separation/reinjection, crude transport, crude refining, product transport, and final combustion. The 28 sample crudes studied as of 2014 have total GHG emissions averaging 585 kilograms CO2 equivalent per barrel of crude oil. These emissions are expected to increase slightly depending on the distance and mode assumed for delivering road transport fuels to end users.
3 It is important to note that the carbon price discovery mechanism in an LCFS credit and the carbon price discovery mechanism in a cap-and-trade system credit operate slightly differently. An LCFS credit price is primarily driven by the difference between the cost of the last alternative fuel used for LCFS compliance and the unit cost of conventional fossil fuel for which the alternative is substituting (for example, the difference between a unit of ethanol and a unit of gasoline). The price thus reflects marginal abatement costs in a very specific market: the fuel market. The cap-and-trade credit price, on the other hand, reflects the marginal carbon abatement cost for alleconomic sectors covered by the scheme. In other words, it reflects the cost of the last unit of carbon avoided/reduced in the broader economy, not just the fuel market.
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