RFS will require more blendstock production

May 8, 2006
The US Energy Policy Act of 2005 has ensured the continued growth of ethanol use through its renewal fuels standard (RFS) provisions.

Scott D. Jensen, Baker & O’Brien Inc., Dallas

David C. Tamm, Baker & O’Brien Inc., Houston

The US Energy Policy Act of 2005 has ensured the continued growth of ethanol use through its renewal fuels standard (RFS) provisions. This growth, however, will be accompanied by a series of problems and complications, many of which are not widely known.

One result is clear: Refiners that are currently making reformulated gasoline (RFG) with methyl tertiary butyl ether will probably require capital investments whether they decide to produce non-oxygenated RFG or reformulated blendstocks for oxygenate blending (RBOB).

This article presents an analysis of the impact of product specifications, market forces, and fuel production economics on ethanol use in various US markets. It also presents a review of current ethanol supply and demand patterns and provides a projection of how these patterns may change due to the Energy Policy Act.

Parts of our analysis were conducted with our proprietary PRISM analysis system, which includes models of all US refineries and the major elements of the crude and product distribution systems. The PRISM database includes process unit capacities, refinery configurations, crude runs, and production profiles, as well as product distribution patterns involving major product pipelines and terminals. The system contains estimates of operating costs, replacement costs, and economic performance on a refinery-by-refinery basis.

Before 2003, ethanol use in gasoline was generally confined to the upper Midwest states and was encouraged by federal and state tax subsidies. Since then, ethanol use has accelerated significantly due to MTBE bans in California, New York, and Connecticut, and the continuation of the oxygenate requirement for RFG.

Energy Policy Act of 2005

The RFS includes targets for annual average use of renewable fuels, which include ethanol derived from grain, cellulosic ethanol, and biodiesel. The RFS also mandates the production of 0.25 billion gal/year of cellulosic ethanol by 2013. All cellulosic ethanol used in motor fuel through 2012 is counted against the mandate at a 2.5 multiplier.

If the minimum mandated 0.25 billion gal/year of cellulosic ethanol is blended, for example, that volume would count as a contribution of 0.625 billion gal/year towards the RFS requirement. Because this 2.5 multiplier directionally lowers the actual mandated volume, and to account for biodiesel use, our estimate for the final 2012 RFS target is approximately 7.0 billion gal/year of ethanol.

The RFS includes a credit trading system to allow administration of the program for all refiners, blenders, and importers. The mandate requires that at least 25% of the annual average RFS volume is used in the summer season (April-September).

Table 1 shows that the RFS average annual average growth rate is 13% for the first 5 years. At an estimated 2005 ethanol use of 3.9 billion gal and its currently rapid growth, compliance with the 2006 mandate seems guaranteed. The question remains whether ethanol can maintain this momentum and exceed the minimum-use requirement or whether the growth will slow and just meet the minimum use.

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Several factors, such as the final phaseout of MTBE, the elimination of the oxygenate requirement for RFG, and future ethanol prices relative to gasoline, will dictate whether ethanol is actually used more than the mandated minimum.

Ethanol’s political story

Since 2000, federal and state political support for ethanol, through various tax subsidies and state mandates, has made it the fastest-growing gasoline component. Ethanol has enjoyed a federal tax subsidy for its use in gasoline since 1978, which is currently 51¢/gal of ethanol blended.

In addition to the federal subsidy, several states also have tax incentives that favor the use of ethanol as a motor fuel.

In addition to its tax subsidy, in most areas conventional gasoline blends with 10% ethanol (gasohol) receive a 1.0-psi waiver in rvp. Ethanol blended into RFG does not receive an rvp waiver. The Chicago-Milwaukee RFG market, however, does receive an allowance of about 0.3 psi for ethanol blends. These waivers reflect an attempt to compensate for the approximate 1.0-psi rvp increase when ethanol is added to gasoline.

Minnesota, Arizona, and Hawaii have enacted specific ethanol blending mandates and many other states have effectively mandated ethanol use through a combination of the RFG oxygenate requirement and an MTBE ban.

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Tables 2 and 3 show the states that have actual or de facto ethanol mandates.

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These incentives and mandates, in addition to market forces, have caused ethanol blending into gasoline to increase to an estimated 3.9 billion gal/year in 2005 from 1.6 billion gal/year in 2000, an impressive 20%/year average growth rate.

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Fig. 1 shows that ethanol use will reach about 4.9 billion gal/year in 2006, which is more than 1 year ahead of the RFS mandated schedule.

Near-term supply, demand

The economics of ethanol production at yearend 2005 were favorable due to low corn prices and relatively high gasoline prices. One can calculate the breakeven cost to produce ethanol with the more common dry-mill process by adding the costs for corn, operating cost, capital recovery, and deducting the value of corn by-products.

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Fig. 2 shows how the breakeven production cost for ethanol has remained relatively flat for the last several years, while the average wholesale gasoline spot price has increased significantly. Because the value of ethanol will tend to track the price for regular gasoline, the graph indicates that the federal subsidy has become less of a requirement to make ethanol a competitive gasoline component.

The spot ethanol price at yearend 2005 rebounded from earlier in the year and was slightly more than parity with gasoline after deducting the 51¢/gal federal subsidy.

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Fig. 3 shows that through 2004 the price of ethanol after deducting the subsidy normally tracked with regular gasoline price. Ethanol spot prices, after subsidy, were lower relative to gasoline for first-half 2005 but have averaged above gasoline since January 2006.

The strong ethanol margins in late 2005 indicated that most ethanol plants were being operated at full capacity and that economics generally supported the continued construction of new plants.

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Fig. 4 shows how the ethanol production capacity has rapidly increased and is estimated to be up to about 6.0 billion gal/year by 2007. At this growth rate, ethanol production capacity will reach 7.5 billion gal/year in 2009.

Ethanol production capacity will likely continue to remain concentrated in the Midwest, although new plants are being built in other areas such as Texas and Colorado. Almost all new plants are dry-mill design and are typically 40-100 million gal/year in capacity.

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Fig. 5 shows the location of major operating and under construction ethanol plants with a capacity of more than 20 million gal/year.

Ethanol consumption increased significantly starting in 2003, in response to the MTBE bans in California, New York, and Connecticut. The distance between the Midwest production sites and the growth markets of consumption on the coasts will put a strain on rail transportation to the new ethanol markets.

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Fig. 6 shows estimated regional consumption of ethanol for 2005.

Short-term consequences

The Act removes the requirement to include oxygenates in RFG after May 5, 2006. Although the Act does not actually ban MTBE, many refiners and blenders will interpret this legislation and the lack of a liability shield as a de facto MTBE ban.

Colonial Pipeline Co. has proposed that gasoline containing MTBE would only be accepted on a case-by-case basis. This implies that much of the MTBE-based RFG previously supplied from the states that make up Petroleum for Defense District 3 (PADD 3: US Gulf Coast) to the Northeast corridor, from Virginia to New York, will likely be replaced with ethanol-based RFG. This will put significant pressure on this market to procure adequate supplies of ethanol and RBOB for the 2006 summer driving season.

It is unclear whether marketers in these areas have sufficient time to prepare for this conversion and how the increased demand for ethanol will affect prices for ethanol and RFG. It is also unclear whether the refiners currently producing RFG with MTBE will be capable of producing the volumes of lower-rvp RBOB that will be required this summer.

Due to these supply issues, we expect that New England markets currently supplied with MTBE-based RFG from foreign imports will continue to be supplied in this manner through 2006. These markets will probably switch to ethanol-based RFG by 2008.

Once refiners and marketers make the investments required to produce and sell RBOB and ethanol-blended RFG, they may find it difficult to justify later changing the supply to non-oxygenated RFG. Removing ethanol from the gasoline pool would require the refiner to make up for the lost octane, which may require further investment.

Unless ethanol costs become high relative to gasoline, those investments may not be justified. We therefore expect that ethanol-blended RFG will be the normal domestic supply for East Coast markets.

Refiners’ response

Our PRISM database includes estimates of gasoline production by grade and formulation for every refinery in the US. The simulator includes the EPA Complex Model and California Air Resources Board (CARB) Phase 3 Predictive Model.

We evaluated the ability of individual refineries to produce increased volumes of both RBOB and conventional blendstock for oxygenate blending (CBOB) based on the following assumptions about ethanol consumption:

• Year-round use in all RFG areas except Texas.

• Year-round use in California.

• Used in all winter oxygenated-fuel program areas.

• A complete MTBE phaseout by 2008.

• Use in Midwestern conventional gasohol markets that allow the 1-psi rvp waiver, as needed, to meet the RFS targets.

The main focus of this article is to estimate how the ethanol mandate will affect refinery gasoline supplies. Although E-85 (85% ethanol and 15% gasoline) has the potential to use large quantities of ethanol, we feel that the sales volume will not become significant until after 2012. E-85 sales currently account for only about 0.3% of total ethanol use and infrastructure and other issues limit its growth.

The results of our analysis are clear. Refiners currently making RFG with MTBE will probably require capital investments, whether they decide to produce non-oxygenated RFG or RBOB.

Non-oxygenated RFG may be economical for those refiners who can compensate for the loss of octane by removing MTBE without using ethanol. Refiners with light naphtha isomerization capacity, for example, will have a greater ability to produce non-oxygenated RFG due to the advantageous RFG blending properties of isomerate.

The growth of non-oxygenated RFG will depend on many factors including ethanol price and overcoming the “boutique” nature of this fuel as it is introduced into the domestic pipeline systems.

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Tables 4 and 5 show estimates of regional refiner production of base gasoline for ethanol blending including RBOB, CBOB, and California Air Resources Board blendstock for oxygenate blending (CARBOB) for 2004 and a projection for 2012.

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Our analysis indicates that refiners in PADDs 1 (East Coast), 2 (Midwest), and 3 will more than double their production of blendstocks for ethanol. PADD 2 refiners will contribute the largest volume increase of these blendstocks due to the regional synergies of ethanol production. The overall production of CBOB and RBOB will almost triple during the 8-year period.

Ethanol blending, gasoline supplies

In aggregate and on an individual refinery basis, blending ethanol into RFG forces higher-rvp blendstocks such as normal butane or pentanes out of the gasoline pool and into other markets. The butane and pentane volume loss in RFG will be about 0.4 gal for each gal of ethanol added to the RFG pool.

In other words, because of volatility limits on RFG, the addition of one gal of ethanol to the RFG pool only increases the size of that pool by 0.6 gal. The butanes and pentanes forced out of the RFG pool do have value in the fuel and petrochemical feedstock market, but they do not contribute to the supply of gasoline.

Ethanol’s energy content is only about two-thirds that of ordinary gasoline, which means that ethanol yields about 70% of the mileage (miles-per-gallon) of gasoline. Motorists using RFG blended with 10% ethanol will therefore get about 3% lower mileage. Combining the butane-pentane effect with the mileage effect, we calculate that adding 1 gal of ethanol to the RFG pool increases the “effective supply” of RFG by 0.42 gal (0.6 x 0.7).

The situation for ethanol blending into conventional gasoline is better than into RFG due to the 1-psi rvp waiver. The 1-psi waiver is sufficient, in most cases, to allow ethanol blending with no volatility changes to the base stock.

The environmental impact of the 1-psi waiver is outside the scope of this article. From a fuel supply prospective, adding 1 gal of ethanol to the conventional gasoline pool increases its effective supply by 0.7 gal due to the mileage penalty.

Clearly, the ethanol mandate will influence the US gasoline supply and will increase investments in the refining industry. The impending removal of MTBE from the gasoline pool will create an intense short-term demand for ethanol as it replaces MTBE in RFG.

For the long run, it remains to be seen if ethanol will remain in summer-grade RFG or be replaced by non-oxygenated RFG. The incremental volume of ethanol required by the mandate will be ultimately used close to the Upper Midwest where it is produced.

The authors

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Scott D. Jensen (sdj@baker obrien.com) is a senior consultant at Baker & O’Brien Inc., Dallas. He has 30 years’ experience in the petroleum refining and chemical process industries and has been consulting since 1991. Before becoming a consultant, he served as refinery manager at Coastal Oil & Gas Corp.’s Wichita, Kan., refinery. Jensen specializes in process plant evaluations, project feasibility studies, plant start-ups, process optimization, and refinery economic evaluations. He holds a BS in chemical engineering from Purdue University and an MBA from Corpus Christi State University.

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David C. Tamm is a senior consultant at Baker & O’Brien Inc., Houston. He has 32 years’ experience in petroleum refining and marketing. The first 22 years of his career included assignments in refinery engineering, economics and planning, retail marketing, and supply and trading with Exxon Corp., Tenneco Corp., and Kerr-McGee Corp. Tamm manages Baker & O’Brien’s PRISM refining industry analysis software and services and consults on refinery and marketing industry economics and market studies. He holds a BS in chemical engineering from Pennsylvania State University and an MBA from the University of Houston.