Ethanol goes prime time
Ethanol plants are another bright spot in an otherwise weak project finance market. Ethanol is an alcohol made most frequently from corn, and it is used both as an additive in gasoline and directly as fuel. There are an estimated 84 ethanol plants in operation currently in the United States, and at least another 30 are in the market for financing.
Chadbourne hosted a round-table discussion in New York about the main issues in ethanol deals, the mistakes that developers make, and how such projects are being financed. The following are excerpts from the discussion. The speakers are Jonathan Phillips, a lawyer in the Chadbourne Houston office, Thomas Byrne, president and chief executive officer of Byrne & Company Limited, a consultancy that has worked with ethanol and bio-diesel developers for 24 years, Tydd Rohrbough, president and chief executive officer of Cornhusker Energy Lexington LLC, an entity that just built an ethanol plant in Nebraska, Peter Nessler, director of the renewable fuels group at FC Stone, a commodity risk firm that helps ethanol producers with hedging strategies, Paul Ho, a vice president of Credit Suisse First Boston, and Keith Martin, a tax partner in the Chadbourne Washington office. The moderator is Todd Alexander, a project finance lawyer with Chadbourne in Houston.
MR. PHILLIPS: The process by which ethanol is derived has been around for several hundred years, with the first commercial application appearing in the US in the early 1900’s. Henry Ford designed the Model T to run on ethanol or gasoline and was a major proponent of ethanol. While he was a forward thinker, he was not sure what the predominate fuel would be in the future. Gasoline was eventually chosen by the market, and ethanol went by the wayside until the early 1970’s.
Then came the Middle Eastern oil embargo and, by the late 1970’s, the US government turned its attention to alternate fuels. Congress gave ethanol an excise tax exemption in 1978. It enacted income tax credits for blenders and small ethanol producers in 1980. The excise tax exemption and the blender credits have played a major role in development of an ethanol industry in the United States. Ten years later, we had the first truly major pro-ethanol legislation, the Clean Air Act Amendments of 1990. By 1999, the harmful effects of a gasoline additive called MTBE came to light, and the first bans on MTBE started being proposed. In October 2004, the JOBS bill passed Congress, and it is probably the most important legislation for the ethanol industry since the Clean Air Act Amendments. The JOBS bill created a “volumetric” excise tax credit for ethanol; instead of an excise tax exemption, the industry was given a credit against federal gasoline excise taxes tied to the volume of ethanol used in vehicle fuel, and the bill also removed the blending percentage requirements that were contained in the Clean Air Act Amendments.
The MTBE bans are creating significant demand for ethanol as a gasoline additive in place of MTBE. In 1999, annual production capacity in the United States was approximately 1.4 billion gallons. In 2003, production jumped to 2.8 billion gallons primarily due to the MTBE bans. Production for 2004 is expected to be around 3.4 billion gallons. Production in October 2004 — the most recent month for which figures are available — was 226,000 barrels per day, tying the record set in September. Nineteen states have banned MTBE to date, which accounts for 1.37 billion gallons of ethanol demand. The remaining states, if we assume a blend of 5.7 to 10% ethanol in gasoline, account for approximately 1.4 billion gallons in demand. There is a lot of speculation about potential demand, and a key assumption in these estimates is the percentage of ethanol used by blenders.
Another key feature of the JOBS bill is a reporting requirement. April of this year will be the first time that all ethanol producers and blenders will have to report to the Internal Revenue Service, and this should give the public a better idea of how much is being produced.
All the major versions of the energy bill that failed in a close vote in late 2003 to pass Congress contained a renewable fuel standard that would have required a certain number of gallons of ethanol to be mixed each year with gasoline. However, ethanol production is already ahead of the mandated levels. The energy bill would have required that 5 billion gallons of ethanol be used each year in gasoline by 2012. In 2004, domestic production was approximately 3.4 billion gallons, and production in 2005 is expected to reach 4.5 billion gallons. The industry wants Congress to raise the bar higher. Chadbourne held a conference call in early November soon after the presidential election results were in about the prospects this coming year for a national energy bill. They remain murky.
The long-term trend is for US government support for cleaner fuels. Each of the presidential candidates spoke out in favor of clean fuel programs. Bush on numerous occasions has supported ethanol, so it is likely we will continue to have strong presidential and Congressional support along with a pro-ethanol lobby. The political instability in the Middle East has produced strong sentiment toward reducing our dependency on foreign oil. This has put renewed focus on renewable fuels and ethanol. It is clear that the market is pushing ethanol as the current renewable, but ethanol has other uses as an extender and oxygenate component.
So, if we assume that the market will continue to grow, the question is what does it take to have a successful ethanol project? One of the major things you need is a strong equity sponsor. Historically, the ethanol business was driven by farmer coops. Hundreds of farmers would invest small sums to raise the equity needed to build an ethanol plant, and they were able to leverage it up through the agricultural credit banks on a 50-50 debt-equity basis. Farmer coop-owned ethanol plants account for approximately 1.1 billion gallons of current production. Archer Daniels Midland Company has approximately 1.2 billion gallons of production, and the remaining 1.1 billion gallons is from other industry players. One reason the industry is so fragmented is that it has had difficulty attracting senior lenders due to the fact that there are non-corollary inputs and outputs. You also cannot arrange a long-term output contract, which makes it hard to persuade lenders that the project will have enough cash flow to cover debt service.
A reputable engineering and construction partner is also important. You need a strong construction contract or EPC agreement. An effective hedging program is essential, too. Pete Nessler will speak to this. There are new ethanol hedges available on the Chicago Board of Trade and the mercantile exchanges. Finally, the financial markets will want to see a strong operational team.
MR. ALEXANDER: Tydd Rohrbough, you developed the Cornhusker project in Nebraska. One of the first decisions a developer has to make is where to build. How do you choose a site?
MR. ROHRBOUGH: We had a well-defined process. We had a core matrix containing 69 criteria, but at the end of the day, it is location, location, location. Most ethanol plants are in rural areas. You can’t build one downtown because they are industrial plants. Next, you focus on where the corn is located. We wanted to make sure the corn we needed would not require taking more than 15% of the total corn produced within a 40-mile radius, so we laid out the whole United States and targeted areas where we could consume less than 15% of the corn supply. When you get out to the rural parts of Nebraska —a state with only a million and a half people — the infrastructure is just not there. We also focused on rail and natural gas supply. We also wanted a spot where there was not another ethanol plant within 15 miles. We also included cattle production —
MR. ALEXANDER: Please explain, for people who are not familiar, the relevance of cattle to an ethanol facility.
MR. ROHRBOUGH: First you buy corn, and then you process the corn by removing the starch to get ethanol, and you end up with high-value animal feed. The market often overlooks the value of this byproduct.
MR. ALEXANDER: Tom Byrne, you have helped a number of projects find the best site. What do you look for?
MR. BYRNE: Definitely location is the first issue. We work with a number of plants outside of the corn belt where how much corn is growing within 40 miles is not one of the factors in site selection. We look first for strong rail access so that the ethanol can get to market. Distiller’s grains are a huge part of making a plant successful. We look at who can use them nearby. For example, we have a project in Texas where there are lots of cattle. If there are chickens or swine nearby, you might look at a little different process that gives you a byproduct closer to a soy meal in place of distiller’s grains.
MR. ALEXANDER: What are the one or two major mistakes you see developers who are not as thoughtful as Tydd Rohrbough make? We know there are 80 or so existing plants and many developers are trying to do more deals.
MR. BYRNE: The largest issue is getting your products right in an ethanol plant. The corn can be used for five or six commodities. If you are looking for a site and you see a set of railroad tracks in front of you, you assume you have access to the best markets and you can get the highest price for your products. That is the biggest error. You need a professional analysis of where those rails go, what products can be sold and what it costs to get your product in and out of that market.
MR. ALEXANDER: Pete Nessler is sitting there patiently waiting to talk; this is his area of expertise. Give us your view.
MR. NESSLER: What Tom said is true. You have to split the US between west and east. There are lots of plants being built today in Iowa and a few more in Nebraska. Look at the demographics of where ethanol is going. There are only a million and a half people in Nebraska and a couple million in Iowa. Your best market for the ethanol is California. When you put the matrix together, it should show that one or two of the products from your facility will have to be shipped there.
MR. ALEXANDER: For those of you without the basic knowledge, if we were to put up a map of the United States and show where the 82 existing plants are located, 78 would be right in the center of the country, forming a bull’s eye. Do you think there is a lot of potential to develop facilities outside of that bull’s eye?
MR. NESSLER: I do. California has a lot of livestock. So does Texas. So does the east coast.
MR. ALEXANDER: Let me question you about rail. You hear about congestion on the rail lines. If you were to build a plant in California or New York, how much additional expense are you talking about to bring the grain to the plant? Do you have to build extra storage so that your plant will not have to rely on just-in-time delivery?
MR. NESSLER: Not to get too deeply into it, but having extra storage makes sense even in the midwest because of the carrying charges. For instance, corn today is $1.65 per bushel, and let’s say nine months from now it is expected to be $2.10. If the market is charging 4¢ a month for carrying costs, having storage will bring your costs down. Most plants have only eight days worth of storage. For a plant on the east coast or west coast, or in the southwest, we recommend 45 days worth of storage. There are glitches in the rail system at certain times of the year, but if you plan ahead for them and you have the space for storage, then you will buy cheaper grain. If there is a rail problem, there will be just as much outbound ethanol going west as grain going east, so it works both ways.
MR. ALEXANDER: So assuming we picked our site, let’s transition with Tydd on picking the proper process design. There are three or four main process designs from which to choose. You looked at them all. How did you choose?
MR. ROHRBOUGH: We did a comprehensive search. We wanted a process that is used in existing plants that have been operating for more than five years, which significantly narrowed the field to just two; at least three years ago, there were only two.
MR. ALEXANDER: In terms of specific factors, what were you looking for? Different people advertise different BTU usage. How did you evaluate them against each other?
MR. ROHRBOUGH: We put up a matrix. One of things we found early on is everyone was selling something different. The first thing we had to do was get a standardized matrix of what the outputs were. Nobody was giving us the same apples-to-apples values. So we started off with something and then broke it down into components. The first thing you have to do is take the corn to starch. You correlate a pound of starch to a pound of fuel and get to a measure of the output. Then we looked at the BTU usage within the process, as to whether or not it was increasing. A lot of people were giving a gallon-to-bushel ratio, but that does not work with corn. You have a wide range of outputs on the back end.
MR. ALEXANDER: Tom Byrne, is that same analysis you would do for your clients?
MR. BYRNE: It goes back to having a comprehensive request for a proposal. The location of the plant is a factor in choice of process. Suppose the plant is in Arizona or Texas where water is an issue. The request for proposals should make clear water is a concern and ask the process providers how they would address it. Different technologies have different levels of energy utilization; some have different chemical utilizations. The ethanol is basically standard. You will get the same ethanol out of each of them. The distiller’s grains have some variation. Look at your potential market for the distiller’s grains. A number of plants are looking at fractionation, or taking the corn apart before it goes into the fermentation process. If you want the distiller’s grains to be right for your particular market, choose a technology that can provide that for the market.
MR. ALEXANDER: Where do you see the technology going? An interesting thing for me, not being an engineer, is the cost of plants that were built five or 10 years ago was so much higher than it is today. Then you hear people talking about cellulosic-based designs, where you would not even be using corn as the basic input. Where do you see things three or five years from now?
MR. BYRNE: About 10 years ago, the ethanol market was basically the ADMs and Cargills of the world that had their own internal operating departments. There was not enough demand for yeast and enzymes to make it worthwhile for companies that provide these inputs to conduct intensive research. Now, with the industry growing quickly, they are spending lots of money on research and development. The same facilities and the same equipment will likely get considerably better yields in the future. Another point to keep in mind is the number of cattle in the United States is not growing significantly. There are a lot of products in corn that can be used for other than just feed. The technology of the future will pull pharmaceuticals and different fibers out of the corn.
MR. ALEXANDER: So instead of 60% or 70% of revenue from the plant being derived from ethanol, these other processes will decrease that fraction. The plant will get 50% of its revenue from ethanol and the rest from other products, and it will not make distiller’s grains?
MR. BYRNE: Ethanol is made strictly from the starch, which happens to be a third of corn, but it is only one component of the corn, and there are other things in a kernel of corn that can be put to better uses than just as feed.
MR. ALEXANDER: Tydd Rohrbough, does this worry you, as someone who owns and has just financed a dry mill plant?
MR. ROHRBOUGH: Not particularly, because these projects are commodity based, and we looked as part of our long-term base plan at other products that come out of corn. We identified 30 that are fermentation based. Our plant will not be a single source facility. We are on the same track in the long term.
MR. ALEXANDER: Suppose someone in the audience plans to invest in an existing plant with dry mill technology. Should he or she assume that the plant will require another capital outlay in five years to equip it to produce a different product mix?
MR. NESSLER: You have to have enough space. The environment will determine what it is possible to do.
MR. ALEXANDER: So it’s important to have lots of space?
Paul Ho, I don’t know whether CSFB has a view on this, but are you worried that you are giving people 7- or 10-year money, given the potential technological changes that may take place?
MR. HO: I think we get comfort from the number of ethanol plants that have been placed into service. You will have to displace the older plants first. We are not overly concerned, and we will also try to get an opinion from an independent engineer that the technology makes sense in the long term.
MR. ALEXANDER: So hopefully we picked a site for our plant that is big enough to expand to accommodate any new technology. Now we need to pick a construction contractor. For those of you who are familiar with power plants and other types of infrastructure projects but have no experience with ethanol, the construction contracts are not what you are used to. Tydd Rohrbough, how did you identify your contractor and how difficult was it to get the contract you wanted?
MR. ROHRBOUGH: It was very difficult to get the contract we wanted. One of our team members comes from Kiewit, which is a fairly large contractor. Three years ago when we came into the industry, many of the companies that were building ethanol plants could not get bonding. Those construction companies are now a lot of larger and can now bond. We had to eliminate many of the potential contractors early on because not all designs allow for the same technology. You should look forward and anticipate what the bank and investors will need. They will want someone to wrap certain risks. If you have a technology provider and an EPC contractor to build it, you need to ask yourself how do you get the EPC contractor to wrap the product.
MR. ALEXANDER: Let’s ask Paul Ho.
MR. HO: We encourage a developer negotiating an EPC contract to spend as much time looking at the financial support for the EPC contract as the technical parameters. The lenders look to the EPC contractor’s credit, and many of these contractors do not have good credit in the sense that the lenders can rely on the creditor to live up to its obligations. So you look to bonding 100% of the contract price. In terms of a performance bond, many of these contractors have been able to build these plants in the past without offering the liquidated damages and performance guarantees that lenders require.
MR. ALEXANDER: For the benefit of our audience, Paul, maybe you could identify some key things that lenders will insist be in the construction contract. For example, does CSFB have specific guidelines for liquidated damages?
MR. HO: Yes. With respect to liquidated damages, we used to say we wanted 20% to 25% debt coverage for energy projects generally, but we are not able to get close to that in the ethanol space. We can get 8% to 10% coverage, and that’s the best we can do. The lenders will have to be comfortable with less than investment-grade credit. The construction risk itself is single B or BB. We’re trying to push the liquidated damages level as much as possible, but at the end of day we have to live with the commercial reality of the industry.
MR. ALEXANDER: Dan Simon from BioFuel Solutions has a question.
MR. SIMON: Are you talking about liquidated damages in the aggregate of 8% to 10%?
MR. HO: Yes, performance plus delay liquidated damages.
MR. SIMON: Is it half and half?
MR. HO: More of the liquidated damages are allocated on the delay side, but combined, it is an 8% to 10% range; that is what the contractors are comfortable providing.
MR. SIMON: Then do you ask for limits of liability?
MR. HO: Yes.
MS. FREDERICK: Paul and Tydd, did you consider using insurance to back up some of the construction and technology risk?
MR. ROHRBOUGH: We tried looking at insurance, but found that it was not available. So the contractor had to step up and provide enough comfort to the owners and the lenders. In addition, bankers tend not to like insurance because of the perceived difficulty of recovering on the policies.
MR. ALEXANDER: Paul, have you seen big changes in the terms of EPC contracts in just the past few years?
MR. HO: There have been gradual changes. The EPC contractors realize that the market is moving away from the traditional sources of equity and debt in terms of financing, and the new lenders coming into the market want more commercial-type terms. The contractors realize they need to move the goal posts a little to make the deals financeable. They are receptive to hearing us, but it has been a gradual process.
MR. ALEXANDER: Moving on from the EPC agreement, Tydd Rohrbough, you had to look at what types of tax incentives were available once you had had your site, design and contractor. They help with the return.
MR. ROHRBOUGH: That was part of our initial review. When we looked at the differences in tax credits that the states were offering, many looked really good, but they could be gone tomorrow, so we had to evaluate that. One of the reasons why we came to Nebraska is because we have a contract with the state and the Department of Revenue. It is not a legislative incentive that might disappear. The $22 million that we could get in Nebraska was much better than the Missouri credit, which was nullified. Minnesota also removed and reinstated its credit. The uncertainly made us wary of what we were being offered in other states.
MR. ALEXANDER: Keith Martin, maybe you can address that and can give everyone a two-minute background on the tax credits available and maybe some of the other tax planning ideas beyond just receiving a 51¢ tax credit.
MR. MARTIN: I will just make four brief points. One is Tydd is smart not to count on locational incentives. A federal appeals court in Ohio declared locational credits unconstitutional last fall. Daimler-Chrysler was given an investment tax credit as an inducement to build an auto plant in Ohio. The court said tax benefits that encourage a company to choose one state over another violate the Commerce Clause of the US constitution. The decision is being appealed.
The ethanol tax subsidy is given to the entity that uses the ethanol to blend with gasoline and not to the developers who decide whether to build plants. The hope is that the credit will have the effect of reducing the cost of ethanol so that more of it will be consumed. This adds to demand for new plants.
The tax subsidy is 51¢ a gallon for ethanol that is at least 190 proof. It is less for ethanol that is at least 150 proof. Blenders have an option of taking it as a credit against federal excise taxes on gasoline or taking it on their income tax returns. Most choose to use it as an excise tax credit.
For the entity that owns the plant, the biggest tax subsidy is the ability to write off the cost of the plant for tax purposes over seven years using the 200% declining-balance method; this is worth 28 cents for each dollar in capital cost. That is the present value of the tax savings from the depreciation deductions. Smaller developers without the tax base to use the depreciation deductions should find a way to share in the benefit indirectly. One way to do this is to bring in a partner with a tax base and allocate him a disproportionate share of the tax benefits in exchange for more cash. Another is to use lease financing for the plant and share in the tax benefits indirectly through a reduced rent. However, before using lease financing, the developer should do a lease-buy analysis. There is an embedded interest rate in the lease rents. The question is whether the embedded rate in the lease is lower than the interest the developer would pay if he borrowed directly to finance the plant.
Those are the main points.
MR. ALEXANDER: Paul Ho, I don’t know whether you want to talk about some other structures that you see to capitalize on taxes other than straight bank debt?
MR. HO: We have structures in which people lend based on the expectation that the project will receive the CCC payment; that’s not ideal. We like to simplify the structure as much as possible.
MR. ALEXANDER: How much value does a lender put on the CCC payment and tax subsidies?
MR. HO: People assume that they augment the cash flow, but when they look at credit ratios, they exclude the additional value. They generally exclude those incentives in calculating the EBITDA ratio to make sure the project is manageable from a credit standpoint.
MR. ALEXANDER: Explain what the CCC payment is.
MR. ROHRBOUGH: The CCC is the Commodity Credit Corporation, which is part of the US Department of Agriculture. The CCC makes a cash payment based on the amount of gallons that you used. The CCC looks at the local corn price, and then makes a cash payment tied to the increase in consumption of corn that you create when you build a plant. It caps out at $7.5 million a year. It is also pooled, so if there are a lot of producers in one year, then there is a proportionate reduction in all payments. Last year, it came out at 59%.
MR. BYRNE: There is a limited amount of money allocated for the federal program. If all of you in the room actually succeeded in building ethanol plants, then each person would end up with $5 in CCC payments.
MR. NESSLER: You have to look at bio-diesel fuel, as well, when you are factoring in the CCC.
MR. ALEXANDER: The next topic is one that got me interested in the financing of ethanol plants in the first place. You have a feedstock that is a commodity, generally corn, and the offtake is primarily ethanol. The prices for these two commodities are not highly correlated, and it is difficult to enter into a long-term, fixed-price contract for either the corn or the ethanol. The banks, many of whom were also involved in the power market, are concerned about having another overbuild situation, analogous to what occurred in the merchant power sector. Pete Nessler, you assist ethanol producers with the mitigation of the risks that arise as a result of this situation. Describe the problem in more detail and talk about what people can do to mitigate the risks associated with having inputs and outputs of an ethanol facility that are not highly correlated.
MR. NESSLER: The one thing we hear from everyone in this community is the question how to mitigate against crisis. If you go back a year, a three to four month hedge is all you could do. Now you can go out 12 to 18 months.
Ethanol is marketed in two or three different ways. You can put forward a flat price, such as $1.50. Another way ethanol is marketed is gas-plus. You have the basic dilemma of whether to base this off a particular gas price or with NYMEX. The Gulf Coast is a fixed reference point, but then you take on potential gasoline risk. The other approach is a spot deal, where management wants to keep 20% open or spot 30% or 40%.
We generally look at things a little bit differently. We look at it from a crush margin viewpoint. We look at where the cost of corn is, and whether your corn is tied to a particular reference point. We have looked at how ethanol values move in relation to NYMEX contracts. It is basic risk mitigation techniques. It does not matter whether the prices are tied to hogs, corn, cattle or ethanol; they all fluctuate and move. One way the ethanol market can mitigate risks going forward is by looking at different swaps based on NYMEX. An ethanol contract will trade on the Chicago Board of Trade starting in March, and there will also be a contract on the Mercantile Exchange. Will they be the answer from heaven? I doubt it, but if the contracts attract enough volume, there will be market makers in them, and we will be able to arrange various derivatives off the back end to help us push the curve forward from the current 12 to 18 months.
MR. ALEXANDER: Paul Ho, what do you think, as a lender, about these risks, given we can have suddenly $3.00 corn and $1.20 ethanol, which in turn means your debt coverage ratio is blown?
MR. HO: One of the publications is saying that the ethanol market is a single B credit. So the lenders are looking at it as a single B credit. They’re not relying on long-term contracts to finance these type of plants. The lenders realize that the business is what it is, so they have to be comfortable with the long-term commodity risk. Now, having said that, they are looking for ways for the capital structure to mitigate the margin risk.
At CSFB, we are proposing a B loan structure in which the lenders expect you to pay them interest plus a nominal amount of principal every year. You are given the luxury of having to pay little principal to the lender, but in good periods, there is a cash sweep mechanism that requires you to pay back more. Those are the kinds of belts and suspenders you can put on the capital structure to help the lenders get comfortable.
MR. ALEXANDER: Tom Byrne, when the developers ask about how to hedge price risk, what do you tell them?
MR. BYRNE: We identify the commodities for the area and look at historical trends. We are often asked whether it makes sense to put a plant in a particular area. History is a good indicator, but history does not always repeat, at least not in the short intervals. We use Monte Carlo simulation to project forward.
MR. ALEXANDER: Pete Nessler, what are some of the biggest mistakes people make?
MR. NESSLER: It’s human nature to be greedy. Last October or November, ethanol was $1.65 a gallon. You had four contracts that were trading at $1.45 to $1.50 for 2005. People might say, “Well, if I can get $1.50 today, why can’t I get it later?” That’s not the way the world works. They put off their crush until 2005 hoping to do better. Alternatively, you can crush now and be done. How many people do it? Right now, you can mitigate up to where you want for your spot risk, and if you want to crush and buy the corn, you’re done; you’ve got it and you clip the coupon.
MR. BYRNE: You have to consider the cost of trading. Some developers come up to the end of a project with only half a million dollars and too little money to pursue such a strategy.
MR. NESSLER: That is a valid point. Sometimes it is done by the banks. A bank might be willing to go out for a margin of 15¢ a gallon; that’s $6 million in a $40 million plant. A developer can try to do inventory financing, securitization against receipts and things like that to raise more money, but the banks will tell you they will lend more if you just take steps to lock in a return. Market profitability is out there for the whole year for people who don’t want to gamble.
MR. STIDOLPH: Russell Stidolph for Whitney & Co., LLC. I think the working capital issues at start up, or even 12 months into operations are the biggest issues. Not being able to hedge your forward production is a big problem. Last year, we started with two plants, and they looked at $3 corn and $1.60 for ethanol, and thought it was the greatest thing in the world. It had a great profit margin, but then the market in corn moved against them a buck a bushel. Unfortunately, the lenders won’t lend against a margin call like that. On top of the economic risk, there is a huge working capital risk. If the lenders would lend, we might see some evolution in the crush margin marketing.
MR. NESSLER: There are horror stories of people looking at their corn in the $2.80 to $2.90 range, and then after brokering their corn, the price went t