The corn ethanol crush spread is no longer driving Renewable Identification Number [RIN] prices. That, at least, has been my takeaway from this week's action in corn ethanol [D6] RIN prices, which are up 41% for the month and 21% for the week (current as of July 17). As a reminder, RINs are the tradeable compliance commodities created by the revised Renewable Fuel Standard [RFS2] to incentivize the mandated levels of biofuel production. They operate as a flexible subsidy for biofuel producers and are paid for by U.S. refiners, in accordance with the latter's share of the annual volumetric mandate under the RFS2. RINs were designed to increase in value as biofuel production costs increase and decrease in value as biofuel market prices increase, thus ensuring that biofuel producers don't lose money on production so long as the mandated volumes aren't being met. After spending their existence trading for $0.01-$0.02 apiece due to overcapacity in the corn ethanol industry, D6 RIN prices soared to nearly $1 in February of this year. A few factors were responsible for this development. First, the 2012 drought caused U.S. corn ethanol production to fall below the mandated level for that year. Second, the drought also caused feedstock (and thus production) costs to soar at a time when gasoline prices remained stable. Finally, the U.S. hit the "blend wall," as the point at which domestic ethanol consumption equals the 10% actual (if not nominal) blending limit with gasoline is known.1 Thanks to the blend wall the mandated volume of ethanol consumption is now greater than the volume that the U.S. fuel infrastructure can handle, forcing refiners to scramble to purchase RINs while retailers still have the capacity to sell the connected biofuels.
As the below figures show, D6 RIN prices set new highs each day this week even as the corn ethanol crush spread (as the spread between gasoline and corn prices is known) reached new highs for the year. With corn ethanol producers paying less money to produce and receiving more money for their product now than at any time since the drought began, D6 RIN prices should be falling. (Note as well the convergence of D4 and D6 RIN prices; at one point in 2011, this spread equaled $1.50.) Instead they've surged.
CORN data by YCharts
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D4 and D6 RIN prices since May 17. Source: EcoEngineers
The other conventional explanation for a sharp increase in D6 RIN prices is a corresponding fall in corn ethanol production. The RINs were designed to provide biofuel producers with enough of a subsidy to ensure that the annual volumetric mandates are met but without providing windfall profits. A fall in production indicates that refiners are not receiving enough of a subsidy, so RIN prices increase in such a situation until production rebounds. However, current production doesn't fit the requirements for this explanation: weekly production only fell slightly last week and is still near its 2013 high (see figure):
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Seasonal factors are also an unconvincing explanation for this steadiness, as weekly production is lower than it was for the same week in 2011 but higher than in 2012 (see figure):
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Admittedly, weekly production will still need to set new highs for the rest of the year if the 2013 volumetric mandate is to be met. That said, this assumes no RIN banking and, regardless, ethanol production is finally moving in the right direction.
Blame the judges
If the conventional theory doesn't explain the recent move in RIN prices, then what does? According to the Wall Street Journal, on Monday, July 15 the D.C. Circuit Court of Appeals vacated the EPA's decision to delay biogenic greenhouse gas [GHG] emission regulations for three years. Biogenic GHG emissions are those that are released from recently living biomass. Unlike GHG emissions from fossil fuels, which are released over a short time period after having been sequestered for millions of years, biogenic carbon has only recently been sequestered. As plants grow, they temporarily sequester water and atmospheric CO2 during photosynthesis in the process of producing carbohydrate and oxygen. The carbon in this carbohydrate is ultimately released back into the atmosphere as CO2, either when the plant dies and decomposes or is digested/combusted for fuel. Pure biorenewable energy pathways (i.e., those pathways with no fossil fuel inputs) are considered to be carbon-neutral or even carbon-negative as a result; any CO2 that is emitted by the pathway was only recently in the atmosphere and the pathway doesn't contribute to net atmospheric CO2 concentrations as a result.
Since the difference between fossil fuel GHG emissions and biogenic GHG emissions is ultimately one of accounting periods there is some amount of uncertainty involved when quantifying the latter's impact on atmospheric GHG concentrations. For example, producing emissions from an annual plant such as corn doesn't increase net atmospheric CO2 concentrations since (1) the CO2 was sequestered only a few months prior during the growing season, and (2) the plant would decompose at the end of the growing season were nature allowed to run its course, resulting in the natural release of the same emissions. Combusting an old-growth forest is a different matter, however, since these have sequestered carbon for decades (if not longer) and will continue to do so well into the future, absent pests or wildfires. Many environmental groups, including those responsible for the aforementioned litigation, are concerned about this uncertainty and want to see biogenic emissions regulated by the EPA as a result.
As any homebrewer knows, biogenic CO2 emissions are a natural byproduct of fermentation, with yeast releasing CO2 as a byproduct during its conversion of carbohydrate to ethanol. Industrial-scale ethanol facilities can produce large quantities of CO2 as a fermentation byproduct. These emissions meet the classic definition of biogenic emissions, however: the carbohydrate is of recent harvest and the resulting emissions will be captured by the next crop. In fact, biofuel pathways employing food or feed crops as feedstock incur the least amount of uncertainty regarding their direct biogenic emissions, as the primary feedstocks (corn, sugarcane, and soya) are both fast growing and short lived. You won't be using trees from an old-growth forest as feedstock for the production of corn ethanol.
The appellate court's ruling replaces the scientific certainty (or, at the very least, decrease in uncertainty) that would have resulted from the EPA's deferral with regulatory uncertainty. The EPA argued that a three-year deferral on the subject of biogenic emissions was necessary to permit the completion of a comprehensive study on the subject. The court ruled, however, that the EPA couldn't apply different standards to different types of GHG emissions when implementing its rulemaking; it can't impose restrictions on one type of emission while postponing restrictions on another pending further study. Practically, then, and in light of the EPA's recent rollout of restrictions on coal-fired power plants, the agency will need to move ahead with its rulemaking on biogenic emissions. As the court pointed out, it can still issue a permanent exemption for biogenic emissions, but it can't wait for scientific certainty before doing so. This increases the odds of an "all-or-nothing" rule that treats all biogenic emissions in the same manner, regardless of their actual impact on net atmospheric CO2 concentrations and differences in our state of knowledge on the different types of emissions.
Taken at face value, this is bad news for corn ethanol producers. Whereas a comprehensive study would have likely excluded the biogenic emissions resulting from corn fermentation from any rulemaking, the court's decision increases the odds of biogenic fermentation emissions being treated in the same manner as those from old-growth forest combustion and restricted as such. Such restrictions could be very expensive to implement; short of strict feedstock sourcing rules (which would require a comprehensive study to develop), about the only way to limit biogenic emissions is to impose carbon capture and sequestration [CCS] requirements on their producers, be it a biomass-fired power plant or a corn facility.
Ethanol's costs are the refiners' tax
What the prima facie scenario doesn't account for, however, is the existence of the RFS2. Recall that RIN values increase as biofuel production costs do, other things being equal, and U.S. refiners are required to purchase those RINs according to their domestic market share in order to demonstrate compliance with the mandate. It's generally been assumed that feedstock costs would be the biggest driver of RIN values on the expense side of the equation. That's not to say that other expenses can't play a role, however. Let's say for the sake of argument that the EPA responds to the appellate court's decision by capping all biogenic emissions from power plants and manufacturing facilities, much as it has done with coal-fired power plants. For facilities with biogenic emissions, about the only option for complying short of shutting down production in such a scenario would be the installment of an expensive CC&S system. If all corn ethanol facilities are covered by the EPA regulation, however, and they all install CC&S systems, then the overall cost of ethanol production will increase, as will RIN prices. Put another way, any expensive regulation imposed on biofuel producers outside of the scope of the RFS2 will ultimately be paid for by U.S. refiners. It doesn't matter whether the cost increase is due to expensive feedstock or expensive regulations; so long as the regulations increase costs for the ethanol industry as a whole, RIN prices will increase to compensate producers.
Let's take the 21% increase (or $0.25/RIN) to D6 RIN prices that have occurred since the court's decision. Based on the 2013 volumetric mandate of 13.8 billion gallons of corn ethanol, this price movement represents an increase to refiners' compliance costs of $3.5 billion - just since Monday. At Wednesday's D6 RIN price, the total cost of compliance for 2013 is now $19.6 billion. That's a far cry from 2012's cost of roughly $264 million. Yes, most of that cost is absorbed by the ten largest publicly-traded U.S. refiners, which boasted a combined operating income of $198 billion in 2012 (see table). Yes, they can avoid those compliance costs by producing biofuels on their own rather than purchasing them from dedicated biofuel producers, much as Valero does. Still, the compliance costs increased from 0.01% of the combined operating income for the refiners listed below in 2012 to 7.4% in 2013 at current prices. Worse still for refiners, the D6 RIN category is ultimately neither the largest nor the most difficult to acquire under the RFS2. Recall that by 2022 the cellulosic biofuel mandate will be the largest by volume at 16 billion gallons, with the D6 RIN category following at 15 billion gallons and the other two categories bringing the total to 36 billion gallons. As the easiest to acquire, D6 RIN prices drive the prices of the other RIN categories. High D6 RIN prices therefore result in high RIN prices across the board.
|Refiner||Million bbl/day||% of U.S. total||2012 operating income (billion)|
|Exxon Mobil (NYSE:XOM)||$64.0|
|Phillips 66 (NYSE:PSX)||$6.6|
|Marathon Petroleum (NYSE:MPC)||$5.3|
|PBF Energy (NYSE:PBF)||$0.9|
|Royal Dutch Shell (NYSE:RDS.A)||$46.4|
Sources: EIA, Google Finance
There are a number of caveats worth mentioning. First, 5.2 billion D6 RINs had been generated and 4.5 billion separated as of May, so not all of the RINs purchased for the year will have traded for $1.42/RIN (although only 1 billion were generated in January, so it's not as if they all will have sold for under $1/RIN either). Second, given the lack of transparency in the RIN market, it's difficult to attribute with complete certainty the price surge since Monday to Monday's appellate court decision; unlike with more liquid markets, we can't see how RIN prices reacted in the minutes following the announcement. Finally, RIN prices are notoriously difficult to predict. Several prominent agricultural economists published papers predicting high D6 RIN prices in 2012 and low prices in 2013; obviously the opposite has happened in both cases. Any technological breakthroughs in the biofuels industry or legislative modifications to the RFS2 could cause RIN prices to collapse just as quickly as they've increased.
These caveats aside, however, this week's RIN price activity raises a new risk for investors in U.S. refiners that hasn't received much attention: that of biofuel restrictions. As I've pointed out, any costs imposed on the biofuels industry as a whole outside of the scope of the RFS2 will ultimately be borne by refiners in the form of higher RIN prices. Just this year we've seen the annual cost of refiner compliance skyrocket, and the scale of the industry's burden is only going to increase as the RFS2 volumetric mandate moves toward its 2022 combined goal of 36 billion gallons. Many environmental groups accuse 1st-generation biofuels such as corn ethanol of causing both ecological and humanitarian disasters. The only development that they would like to see more than the imposition of expensive regulations on biofuel producers is that of the bill being passed to U.S. refiners. As this week's decision from the U.S. Court of Appeals for the DC Circuit on biogenic GHG emissions demonstrated, this is a very real risk to refiners under the RFS2. Investors in U.S. refiners should account for this risk accordingly.
1 The EPA legally permits ethanol blends of up to 15%, although retailer and consumer opposition has prevented its adoption at more than a handful of Midwestern pumps.