A fact frequently lost amid the sound and fury over biofuel policy is that biofuels were originally conceived in the U.S. as a means of reducing the country's dependence on imported petroleum. The revelation that several of the 9/11 hijackers came from Saudi Arabia, one of the world's primary petroleum exporters, set in motion a national effort to increase U.S. energy security via increased domestic production of transportation fuels. Since shale oil had yet to reach the market at the time, this effort focused first on hydrogen fuel cells before ultimately settling on corn ethanol. The goal of environmental security was largely ignored in the original Renewable Fuel Standard [RFS1], which mandated the use of increasing volumes of corn ethanol over time. It was only in 2007 with the creation of the revised Renewable Fuel Standard [RFS2] and the greenhouse gas reduction thresholds that it imposed on participating biofuels that environmental security became an important goal as well.
Critics of biofuels have long pointed out that these fuels are far from the only non-petroleum transportation fuels available to the market and thus capable of increasing U.S. energy security. Coal-to-liquid [CTL] synthetic fuels famously powered the Nazi war machine during World War II. More recently, several giant gas-to-liquid [GTL] facilities are being constructed or planned around the world. Given the abundance of shale gas available in the U.S., critics ask, why not further the energy security goal by including these pathways within the RFS2? No, the resulting fuels are not renewable and do not contribute to environmental security, but the same has been said of corn ethanol, which is responsible for the vast majority of current production under the RFS2. These points notwithstanding, an effort to expand the RFS2 into a broader "open fuels" standard failed in 2011. Given the recent inability of Congress to even pass the Farm Bill, it is unlikely that the RFS2 will be modified to include non-renewable alternative fuels anytime soon.
The EPA to the rescue?
Supporters of the proposed Open Fuel Standard found an unlikely ally in the U.S. Environmental Protection Agency [EPA] earlier this year, however, as the agency appears to have found a means of increasing the consumption of natural gas in the transportation sector while also reducing the sector's greenhouse gas emissions. The EPA is responsible for implementing the RFS2, a task that includes determining which biofuel pathways meet the greenhouse gas reduction threshold required for participation in the mandate. In a final rule dated March 5, it determined that a number of additional biofuel pathways met the 60% greenhouse gas reduction threshold required of cellulosic biofuels, the strictest category in the program. The March 5 rulemaking deviated from previous rulemaking by announcing that large amounts of natural gas could be employed in the production of these cellulosic biofuels; specifically, up to 55% of the energy needed to produce each gallon on a Btu basis could be derived from natural gas, with the remainder sourced from lignocellulosic biomass. Due to the lack of emissions from lignocellulosic biomass and the relatively low emissions from natural gas, the EPA determined that this could occur while still reaching the 60% reduction threshold. Since the cellulosic biofuel category must meet the strictest reduction threshold, the rule also implicitly makes it possible for non-cellulosic pathways to also derive a large fraction of their energy requirements from natural gas. The below figure compares the maximum natural gas consumption for the pathways in the March 5 rule with those approved in a previous rule [pdf] (the pathways included in the March 5 rule are marked with an asterisk).
Maximum natural gas usage in approved RFS2 pathways (Source: EPA)
While the overall Btus that can now be derived from natural gas for a qualifying pathway have not increased substantially over the amount permitted for the corn ethanol pathway in the previous rule, what is particularly important here is the potential growth in approved natural gas consumption that can now occur under the RFS2. Most of today's corn ethanol production capacity had already been constructed at the time of the RFS2's implementation and this was grandfathered in by the EPA, regardless of the actual greenhouse gas emission reduction threshold of the included facilities. (Much of the capacity derives some of its energy from coal, which has a larger carbon footprint than natural gas). Unlike corn ethanol production, annual cellulosic biofuel production is mandated to increase by nearly 16 billion gallons [pdf] between 2013 and 2022. This production could thus consume up to nearly 1 billion MMBtus of natural gas annually, assuming usage of 59,000 Btus/gal. This calculation also excludes renewable diesel and jet fuel production via lipids hydroprocessing, which can consume up to 39,000 Btus of natural gas per gallon under the RFS2 but for which the EPA has yet to set a 2022 volume mandate. Far from being excluded from biofuel policy, then, the EPA's most recent rule makes it possible for natural gas to play an important role within the most important category of the RFS2.
Perhaps more importantly, the ability to source much of biofuel production's energy requirements from natural gas has the potential to stretch existing supplies of lignocellulosic feedstock much further. A major limiting factor in the production of cellulosic biofuels is the high expense of feedstock transport relative to that of more conventional feedstocks such as corn. Many cellulosic biofuel pathways also use biomass to meet both the feedstock and process energy requirements. This cost reduces the optimal capacity of cellulosic biofuel facilities below the level provided by economies of scale, making cellulosic biofuel production more expensive than they otherwise would be. The ability to replace half of the pathway's biomass energy requirement with natural gas could feasibly double the current capacity constraint for facilities able to utilize it. Not all pathways would fare equally well under this scenario; some, such as cellulosic ethanol via hydrolysis and fermentation, source all of their energy requirements from lignin that would otherwise be disposed of as a waste product. Thermochemical routes capable of converting the lignin fraction of the biomass into biofuel along with the cellulose and hemicellulose fractions would be more likely to benefit, however, since the use of natural gas to provide process heat would allow more biomass to be converted to biofuel.
The potential impact of the March 5 rulemaking can be easily exaggerated so a few caveats are in order. First, while 1 billion MMBtus is a large figure, it is equal to less than 4% of the U.S. natural gas production projected by the Energy Information Administration to occur in 2022 by its 2013 Annual Energy Outlook [AEO]. (That said, it is more than 30% higher than the net U.S. exports via both pipeline and LNG projected for 2022.) Second, there is no guarantee that cellulosic biofuel producers will consume the maximum amount of natural gas permitted by the EPA under the RFS2. While lignocellulosic biomass is unlikely to be cheaper than natural gas in the near future, natural gas consumption within the RFS2 is currently limited to "process energy"; it cannot replace biomass as feedstock, for example, either in whole or in part. Furthermore, there is a lack of clarity in the rules regarding whether or not natural gas used for hydroprocessing, whereby natural gas-derived hydrogen is used to deoxygenate and hydrogenate intermediate fuel products, is considered to be feedstock energy or process energy. Categorizing the step as feedstock energy would greatly limit the amount of natural gas that could be consumed by the pathways as a practical matter, maximum usage amounts aside. (I sent a query to the EPA regarding this back in May but have yet to receive an answer as of the time of writing. An argument could be made both ways since hydrogenation adds energy to the biofuel, much but not all of which is removed via hydrodeoxygenation as water.)
As indicated earlier, the EPA's March 5 rule is unlikely to have a significant impact on natural gas prices due to the vast amount of U.S. production that is expected to occur over the next decade. With that said, it does have the potential to substantially reduce cellulosic biofuel production costs by allowing producers to source up to 55% of their pathway energy requirements from inexpensive natural gas rather than lignocellulosic biomass. This will be particularly true if the EPA categorizes hydroprocessing as process energy, given the large number of producers to utilize the step. Diamond Green Diesel - a joint venture between Darling International (NYSE:DAR) and Valero Energy (NYSE:VLO), Dynamic Fuels - a joint venture between Syntroleum (NASDAQ:SYNM) and Tyson Foods (NYSE:TSN), KiOR (NASDAQ:KIOR), Neste Oil (OTC:NTOIF), Rentech (NASDAQ:RTK), and Solazyme (NASDAQ:SZYM) all employ at least one hydroprocessing step for biofuel production. One of my previous articles discussed how much of an impact inexpensive shale gas will have on pathways employing a hydroprocessing step, so the ability to utilize natural gas-derived hydrogen while still qualifying for the RFS2 would greatly improve the economic feasibility of advanced biofuel production.
The EPA determined on March 5 that natural gas can play an important role in biofuel production, with qualifying biofuel pathways now allowed to source up to 55% of their energy requirements from natural gas. While this development is unlikely to greatly affect the domestic price of natural gas due to the vast amount of U.S. production expected over the next decade, it has the potential to significantly reduce the production costs of many biofuel pathways, particularly those yielding cellulosic biofuels. Production cost decreases could arise in two different ways: via the direct reduction of operating costs due to the low price of natural gas, and via the increase in optimal facility capacity (and subsequent reduction in production costs) resulting from reduced biomass demand. These benefits will not affect all pathways equally since some can utilize more natural gas than others, although a number of biofuel producers are poised to benefit from the EPA's March 5 rule in the future.