COFFEYVILLE RESOURCES, INC. Securities Registration Statement (S-1) MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

The following is an excerpt from a S-1 SEC Filing, filed by COFFEYVILLE RESOURCES, INC. on 2/11/2005.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations in conjunction with our financial statements and related notes included elsewhere in this prospectus. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including, but not limited to those set forth under "Risk Factors" and elsewhere in this prospectus.

Overview and Executive Summary

We are one of the largest independent high complexity petroleum refiners and marketers in the mid-continental U.S. and the lowest cost producer and marketer of upgraded nitrogen fertilizer products in North America. Our operations are organized into two business segments: petroleum and nitrogen fertilizer. Our petroleum business includes a complex oil refinery in Coffeyville, Kansas, a crude oil gathering system throughout Kansas and Northern Oklahoma, and storage and terminalling facilities for asphalt and refined fuels in Phillipsburg, Kansas. Our refinery operates in close proximity to our primary customer base and benefits from favorable crude oil supply and product distribution logistics. Our nitrogen fertilizer business in Coffeyville, Kansas, includes a petroleum coke gasification plant that produces high purity hydrogen that is converted to ammonia at our ammonia plant and upgraded to urea ammonium nitrate (UAN) at our UAN plant. We operate the only nitrogen fertilizer plant in North America utilizing a coke gasification process to generate hydrogen feedstock that is further converted to ammonia for the production of nitrogen fertilizers. This currently provides us with a significant competitive advantage due to the high prevailing and volatile natural gas prices.

Factors Affecting Comparability

Our results over the past three years and over the nine months ended September 30, 2003 and 2004 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.

Coffeyville Group Holdings, LLC was formed in 2003 by an investor group led by Pegasus specifically for the acquisition Farmland's petroleum business and a nitrogen fertilizer plant. On March 3, 2004, Coffeyville Group Holdings, LLC completed the acquisition of certain assets of Farmland that comprise our business. As a result, financial information as of and for the periods prior to March 3, 2004 discussed below and included elsewhere in this prospectus was derived from the financial statements and reporting systems of Farmland. Prior to March 3, 2004, Farmland's petroleum division was primarily comprised of our current petroleum business. Our nitrogen fertilizer plant, however, was only one facility within Farmland's eight-plant nitrogen fertilizer manufacturing and marketing division.

A new basis of accounting was established on the date of the transaction and, therefore, the financial position and operating results after March 3, 2004 are not consistent with the operating results before the acquisition date. However, management believes the most practical way to comment on the results of operations due to the short period from January 1, 2004 to March 2, 2004 is to compare the sum of the operating results for both periods in 2004 with the corresponding period in 2003.

Our financial statements prior to March 3, 2004 reflect an allocation of certain general corporate expenses of Farmland, including general and corporate insurance, property insurance, corporate retirement and benefits, human resource and payroll department salaries, facility costs, information services, and information systems support. For the years ended December 31, 2001, 2002 and 2003, and for the 62 day period ending March 2, 2004, these costs allocated to our businesses were approximately $4.2 million, $6.3 million, $12.7 million and $3.8 million, respectively. Our financial statements prior to March 2, 2004 also reflect an allocation of interest expense from Farmland. These allocations were

made by Farmland on a basis deemed meaningful for their internal management needs and may not be representative of the actual expense levels required to operate the businesses at that time or as they have been operated after March 3, 2004.

The financial statements for our nitrogen fertilizer business prior to February 2002 reflect the impact of an operating lease structure utilized by Farmland to finance our nitrogen fertilizer plant. The cost of this plant under the operating lease was $263.0 million and the rental payments were $18.7 million and $0.3 million for the periods ended December 31, 2001 and 2002, respectively. In February 2002, Farmland refinanced the operating lease into a secured loan structure, which effectively terminated the lease and all of Farmland's obligations under the lease.

During 2002, our refinery was shut down for approximately six weeks in order to perform planned major maintenance. We reported costs of $17.0 million associated with this shutdown using the direct expense method of accounting and included this expense in the cost of sales during 2002. We have planned major maintenance scheduled at our refinery for late in the third quarter or early in the fourth quarter in 2006 and 2010.

In December 2002, Farmland implemented Statement of Financial Accounting Standards (SFAS) No. 144, resulting in a reorganization expense from the impairment of long-lived assets. Under this Statement, recoverability of assets to be held and used is measured by comparison of the carrying amount of an asset to the estimated undiscounted future net cash flows expected to be generated by the asset. It was determined that the carrying amount of the petroleum assets and the carrying amount of our nitrogen fertilizer plant in Coffeyville exceeded their estimated future undiscounted net cash flows and, as a result, impairment charges of $144.3 million and $230.8 million were recognized for each of the refinery and fertilizer assets, based on Farmland's best assumptions regarding the use and eventual disposition of those assets. In 2003, as a result of additional information acquired through the bankruptcy court's sales process, Farmland revised its estimate for the amount to be generated from the disposition of these assets, and an additional impairment charge was taken. The charge to earnings in 2003 was $4.0 million and $5.7 million, respectively, for the refinery and fertilizer assets.

During the first 11 months of 2001, Farmland operated a joint venture with CHS, Inc. called Country Energy, LLC. During this period, our refinery's output was marketed on an agency basis and sales for Farmland's petroleum business included 41% of all sales sold through Country Energy. These sales included CHS's portion of the output of the NCRA refinery at McPherson, Kansas, CHS's refinery at Laurel, Montana and our refinery, as well as gasoline and distillates purchased from third parties for resale, and wholesale propane, lubricants and petroleum products. After the termination of the joint venture, Farmland entered into a propane marketing and sale agreement with CHS which also had an impact on the financial results of Farmland's petroleum division during that 11 month period. Country Energy's and Farmland's interests in the propane marketing and sale agreement were sold to CHS in November 2001 for a gain of $18.0 million. After these transactions, the petroleum business revenue consisted primarily of the output of the Coffeyville refinery.

In December 2001, Farmland entered into an agreement to sell to CHS all of Farmland's refined products produced at the Coffeyville refinery through November 2003. The selling price for this production was set by reference to daily market prices within a defined geographic region. Subsequent to the expiration of this contract, the petroleum business began marketing its refined products in the open market to multiple customers.

During the first quarter of 2001, our nitrogen fertilizer plant was in the startup and commissioning phase. As a result, our intermittent operations of the plant and production during that quarter are not representative of the current operations of our nitrogen fertilizer plant.

For the periods ending December 31, 2001, 2002, 2003 and the first 62 days of 2004, Farmland's sales of nitrogen fertilizer products were subject to a marketing agreement with Agriliance, LLC. Under the agreement, Agriliance was responsible for marketing substantially all of Farmland's nitrogen

fertilizer products in return for a commission, represented as a percentage of dollar sales volume. Over this period, the stated commission rate varied from 7.0% to 2.5% depending on the time period, the product and the customer. In 2001 through 2003 the favorable impact on gross margins would have been in the range of $2.0 million to $4.5 million per year. In addition to the direct impact of the discounts offered to Agriliance, there were indirect impacts on the earnings as result of the business being a part of a larger marketing effort and product being shipped longer distances to avoid competing with other Farmland facilities or facilities from which Agriliance was acquiring product. Such effects are difficult to quantify and may make period to period comparisons of our results less meaningful. Subsequent to our acquisition of the nitrogen fertilizer business, we began selling our nitrogen fertilizer products directly to dealers and distributors and focused on customers that were the most freight logical to our facility.

On May 31, 2002, Farmland filed for bankruptcy. One of the most significant consequences to the petroleum business was the inability of Farmland to acquire its desired crude slate and the necessity for Farmland to prepay for crude oil. We have not been required to make similar prepayments for our crude oil supply since we commenced operations as a stand-alone entity. The impact of this and other factors is difficult to quantify and may make period to period comparisons of our results less meaningful.

Industry Factors

Earnings for our petroleum business depend largely on refining industry margins, which have been and continue to be volatile. Crude oil and refined product prices depend on factors beyond our control. While it is impossible to predict refining margins due to the uncertainties associated with global crude oil supply and global and domestic demand for refined products, we believe that refining margins for U.S. refineries will generally remain above those experienced in the period from and including 1998 through 2003 as growth in demand for refining products in the U.S., particularly transportation fuels, continues to exceed the ability of domestic refiners to increase capacity. In addition, global supply and other factors have constricted the extent to which product importation to the U.S. can relieve domestic supply deficits. This phenomenon is more pronounced in our marketing region, where demand for refined products has exceeded refining production by approximately 38% since 1997.

Over the first nine months of 2004, the market price of distillates relative to crude oil was above average due to low industry inventories and strong consumer demand brought about by the relatively cold winter weather in the Midwest and high natural gas prices. This phenomenon led to an increase in industrial users switching from natural gas to fuel oil and the markets anticipation of a fuel oil deficit in the winter of 2003-2004. In addition, gasoline margins were above average, and substantially so during the spring and summer driving seasons, primarily because of very low pre-driving season inventories exacerbated by high demand growth. The increased demand for refined products due to the relatively cold winter and the decreased supply due to high turnaround activity led to increasing refining margins during the early part of 2004.

When product demand spikes, this demand is met largely by refineries capable of processing only light/sweet crude. This is due to the fact that a majority of refineries are equipped to process only light/sweet crude. This puts upward pressure on light/sweet crude pricing. As a result, refineries such as ours, which can process heavy/sour crudes are able to benefit. This is evident in market conditions such as those that existed in 2004 when refining margins widened.

Average discounts for sour and heavy sour crude oil compared to sweet crude increased in the first nine months of 2004 from already favorable 2003 levels due to increasing worldwide production of sour and heavy sour crude oil relative to the worldwide production of light sweet crude oil coupled with the continuing demand for light sweet crude oil. In 2003, the discount for West Texas Sour (WTS) versus West Texas Intermediate (WTI) widened to $2.75 per barrel and this sweet/sour spread continues to exceed recent average historic levels. WTI continues to trade at a premium to WTS due to continued

high demand for sweet crude oil resulting from the more stringent fuel specifications implemented in the United States and Europe and the higher margins for light products. We expect to continue to recognize significant benefits from our ability to meet current fuel specifications using predominantly heavy and medium sour crude oil feedstocks as the discount for heavy and medium sour crude oil compared to WTI continues at its current level.

We expect refined product supply and demand balances to tighten worldwide as growth in demand for refined products is expected to exceed net capacity growth, particularly for transportation fuels. We expect that a portion of the supply growth due to new capacity built by foreign refiners and the continued de-bottlenecking and expansion of existing refineries will likely be offset by more stringent environmental specifications that will place further supply pressure on clean fuel availability resulting from the high capital requirements to meet worldwide low-sulfur gasoline and diesel specifications. We expect that the worldwide growth in the production of sour and heavy sour crude oil will continue to exceed increases in the production of light sweet crude oil and that this, along with the continuing demand for light sweet crude oil, will support a wide spread between the prices of light sweet and heavy sour crude oil. Our refinery is able to extract economic benefit under these conditions because of its ability to accommodate heavy crude in the crude slate and retain value from the by-products of that refining process.

Earnings for our nitrogen fertilizer business depend largely on the prices of nitrogen fertilizer products, the floor price of which is directly influenced by natural gas prices. Natural gas prices have been and continue to be volatile. We expect nitrogen fertilizer product prices to remain high by historical standards as well as continued growth in demand for nitrogen fertilizer products in the U.S., particularly for UAN. This trend is more pronounced in our region, the Midwest, where demand for nitrogen fertilizer products has exceeded production and there is limited fertilizer transportation infrastructure. We believe this will continue to provide us with relatively high margins on our nitrogen fertilizer products.

Factors Affecting Results

Petroleum Business

In our petroleum business, earnings and cash flow from operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire feedstocks and the price for which refined products are ultimately sold depends on factors beyond our control, including the supply of, and demand for, crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. While our net sales fluctuate significantly with movements in crude oil prices, these prices do not generally have a direct long-term relationship to net earnings. Because we apply first-in, first-out accounting to value our inventory, crude oil price movements may impact net earnings in the short term because of instantaneous changes in the value of the minimally required, unhedged on hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect such changes.

Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the price of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors' facilities, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for

gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. For further details on the economics of refining, see "Industry Overview-Oil Refining-Industry Economics of Refining."

In order to assess our operating performance, we compare our gross margin against an industry gross margin benchmark. The industry gross margin is calculated by assuming that five barrels of benchmark light sweet crude oil is converted, or cracked, into three barrels of conventional gasoline and two barrels of distillate. This is referred to as the 5-3-2 crack spread. Because we calculate the benchmark margin using the market value of New York gasoline and diesel fuel against the market value of West Texas Intermediate crude oil, we refer to the benchmark as the New York 5-3-2 crack spread, or simply, the 5-3-2 crack spread. The 5-3-2 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude refinery would earn assuming it produced and sold the benchmark production of conventional gasoline and distillate.

Because our refinery has certain feedstock costs and/or logistical advantages as compared to a benchmark refinery, our gross margin generally exceeds the 5-3-2 crack spread by a significant amount. Our refinery is able to process significant quantities of heavy and medium sour crude oil that has historically cost less than WTI crude oil. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil, to the price of WTI crude oil, a light crude oil. The spread is referred to as our consumed crude differential. Our consumed crude differential will move directionally with changes in the WTS differential to WTI and the Maya differential to WTI as both these differentials indicate the relative price of heavier, more sour slate to WTI. The correlation between our consumed crude differential and published differentials will vary depending on the volume of heavy medium sour crude we purchase as a percent of our total crude volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.

The value of our products is also an important consideration in understanding our results. We produce a high volume of premium products, such as gasoline, diesel and heating oil. Our refined products benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices of our products have to be high enough to cover the logistics cost for Gulf Coast refineries to ship into our region.

Our operating cost structure is also important to our profitability. Major operating costs include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy and the most important benchmark for energy costs is the value of natural gas. Our variable operating costs are largely energy related and therefore sensitive to the movements of crude price. We believe our fixed operations costs are low as compared to our peers, partially because of the flexibility our current union contracts provide us.

Consistent, safe, and reliable operations at our refineries are key to our financial performance and results of operations. Unplanned downtime of our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors.

Other than crude we gather ourselves, we purchase crude oil from third parties using a credit intermediation agreement. Our credit intermediation agreement is structured such that we take title, and the price of the crude oil is set, when it is delivered at the crude oil tank farm adjacent to our refinery. This agreement significantly reduces the investment that we are required to maintain in petroleum inventories relative to our competitors and reduces the time we are exposed to market fluctuations before the inventory is priced to a customer. Because petroleum feedstocks and products are essentially commodities, we have no control over the changing market value of our investment. Therefore, the lower target inventory we are able to maintain significantly reduces the impact of

commodity price volatility on our hydrocarbon inventory position relative to other refiners. This target inventory position is generally not hedged. To the extent our inventory position deviates from the target level, we consider risk mitigation activities usually through the purchase or sale of futures contracts on the New York Mercantile Exchange (NYMEX). Our hedging activities carry customary time, location and product grade basis risks generally associated with hedging activities. Because most of our titled inventory is valued under the first-in, first-out costing method, price fluctuations on our target level of titled inventory have a major effect on our financial results unless the market value of our target inventory is increased above cost.

Nitrogen Fertilizer Business

In our nitrogen fertilizer business, earnings and cash flow from operations are primarily affected by the relationship between nitrogen fertilizer product prices and operating costs. Unlike our competitors, we use minimal natural gas as feedstock and, as a result, are not directly heavily impacted in terms of cost, by high or volatile swings in natural gas prices. Instead, our coke feedstock is primarily supplied by our adjacent oil refinery. The price for which nitrogen fertilizer products are ultimately sold depends on numerous factors beyond our control, including the supply of, and demand for, nitrogen fertilizer products which, in turn, depend on, among other factors, the price of natural gas, cost and availability of fertilizer transportation infrastructure, changes in the world population, weather conditions, grain production levels, the availability of imports, and the extent of government intervention in agriculture markets. While our net sales could fluctuate significantly with movements in natural gas prices during periods when fertilizer markets are weak and sell at the floor price, high natural gas prices do not force us to shut down our operations because we employ coke as a feedstock to produce ammonia and UAN.

Nitrogen fertilizer prices are also affected by other factors, such as local market conditions and the operating levels of competing facilities. Natural gas costs and the price of nitrogen fertilizer products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors' facilities, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products. For further details on the economics of fertilizer, see "Industry Overview-Nitrogen Fertilizer Industry-Pricing of Fertilizer Products."

In order to assess our operating performance, we calculate netbacks, or plant gate price, to determine our operating margin. Netbacks refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs. Given our use of low cost petroleum coke, we are not presently subjected to the high raw materials costs of competitors who use natural gas. Instead of experiencing high variability in the cost of raw materials, we utilize less than 1% of the natural gas relative to other natural gas based fertilizers and we estimate that we maintain our competitive advantage at natural gas spot prices in the range of $1.50 to $2.50 per million Btu and above. The spot price for natural gas at Henry Hub on September 30, 2004 was $5.84 per million Btu.

Because our fertilizer plant has certain logistical advantages relative to end users of ammonia and UAN and demand relative to production remains high, we can afford to target freight-advantaged destinations in the U.S. farm belt. We do not incur any intermediate transfer, storage, barge freight or pipeline freight charges. Currently, our freight advantage over U.S. Gulf Coast importers is approximately $65 per ton for ammonia production and $37 per ton for UAN production. Such cost differentials represent a significant portion of the market price of these commodities. For example, since the end of 2003, ammonia prices have fluctuated between $268 and $329 per ton, and UAN prices have fluctuated between $156 and $195 per ton. Selling products to customers in close proximity to our fertilizer plant while keeping transportation costs low is key to maintaining profitability and understanding our results.

The value of our nitrogen fertilizer products is also an important consideration in understanding our results. We upgrade two-thirds of our ammonia production into UAN, a product that presently generates a greater value for the upgraded ammonia. As the largest fully integrated single train UAN production facility in North America, UAN production is a major contributor to our profitability. Furthermore, given the high demand for UAN relative to production and transportation costs that Gulf Coast importers face, we anticipate favorable operating results from our UAN production capabilities.

Our operating cost structure is also important to our profitability. Using a coke gasification process, we have higher fixed costs than natural gas based fertilizer plants. Major operating costs include electrical energy, employee labor, maintenance, including contract labor, and outside services. The predominant variable cost is the cost of petroleum coke that we obtain primarily from our refinery.

Consistent, safe, and reliable operations at our nitrogen fertilizer plant are critical to our financial performance and results of operations. Unplanned downtime of our nitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors.

Results of Operations

The following tables provide supplementary income statement and operating data and do not represent income statements presented in accordance with U.S. generally accepted accounting principles (GAAP). Selected items in each of the periods are discussed separately below.

Net sales consist principally of sales of refined fuel and nitrogen fertilizer products. For the petroleum business, net sales are mainly affected by crude oil and refined product prices, changes to the input mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value light products, such as gasoline, rather than lower value finished products, such as petroleum coke. In the nitrogen fertilizer business, net sales are primarily impacted by manufactured tons and nitrogen fertilizer prices.

Gross margin is net sales less raw material cost, inclusive of transportation, and all other components of cost of sales except operating expenses which are displayed separately for discussion purposes. Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads, see "-Factors Affecting Results." We discuss our results of petroleum operations in the context of per barrel consumed crack spreads and gross margin. Our nitrogen fertilizer gross margin is principally driven by the relationship or margin between nitrogen fertilizer products and the cost of petroleum coke. In contrast to our petroleum business, gross margin is not a significant indicator of profitability in the nitrogen business as the vast majority of expenses associated with our nitrogen business are classified as operating expenses.

We define Adjusted EBITDA as EBITDA plus or minus the following items:
(1) for the petroleum business, (a) during the year ended December 31, 2001, a gain of $18.0 million, which was recorded for the disposition of our Predecessor's share in Country Energy, LLC, (b) during the year ended December 31, 2002 an asset impairment charge of $144.3 million related to the write-down of our refinery to fair market value, (c) during the year ended December 31, 2003, an additional charge of $3.9 million related to the asset impairment of our refinery based on the expected sale price of the assets in the Transaction, and (d) for the 212 day period ended September 30, 2004, a write-off of $6.2 million of deferred financing costs in connection with refinancing of our indebtedness on May 10, 2004, and (2) for the nitrogen fertilizer business, (w) for the periods ended December 31, 2001 and 2002, rental payments of $18.7 million and $0.3 million, respectively, to reflect the termination of such rental payments under an operating lease structure utilized by Farmland to finance the nitrogen

fertilizer plant, (x) during the year ended December 31, 2002 an asset impairment charge of $230.8 million related to the write-down of our nitrogen fertilizer plant to fair market value, (y) during the year ended December 31, 2003, an additional charge of $5.7 million related to the asset impairment of our nitrogen fertilizer plant based on the expected sale price of the assets in the Transaction, and (z) during the 212 day period ended September 30, 2004, a write-off of $1.0 million of deferred financing costs in connection with refinancing of our senior secured credit facility on May 10, 2004.

For a reconciliation of EBITDA and adjusted EBITDA to net income, see notes 3 and 4 to "Selected Historical Consolidated Financial Data."

Succesor and Predecessor Predecessor Combined

Predecessor

Nine Months Ended Nine Months Ended Year Ended December 31, September 30, September 30, Consolidated -------------------------------- ------------------- ---------------------- Financial Results 2001 2002 2003 2003 2004

(in millions)
Net sales $ 1,630.2 $ 887.5 $ 1,262.2 $ 937.2 $ 1,231.7 Gross margin 189.5 125.3 205.7 147.7 216.2 Operating expenses 163.9 183.5 141.8 102.9 110.2 Depreciation and 19.1 30.8 3.3 2.7 2.0 amortization
Operating income (20.8 ) (449.9 ) 29.4 16.9 92.3
(loss)
Net income (loss) (19.4 ) (465.7 ) 27.9 15.3 51.1 EBITDA 18.0 (423.2 ) 32.5 19.3 86.2 Adjusted EBITDA 18.7 (47.8 ) 42.1 28.9 93.4

Succesor and Predecessor Predecessor Combined

Predecessor

Nine Months Ended Nine Months Ended Year Ended December 31, September 30, September 30, Petroleum Business -------------------------------- ------------------- ---------------------- Financial Results 2001 2002 2003 2003 2004

(in millions)
Net sales $ 1,581.7 $ 829.0 $ 1,161.3 $ 865.5 $ 1,151.9 Gross margin 157.7 82.6 121.3 87.3 147.8 Operating expenses 103.8 112.8 82.2 60.5 66.2 Depreciation and 18.6 15.8 2.1 1.7 1.2 amortization
Operating income 31.8 (183.9 ) 21.5 12.1 74.2
(loss)
EBITDA 70.0 (172.1 ) 23.5 13.6 68.3 Adjusted EBITDA 51.9 (27.9 ) 27.4 17.5 77.0

Succesor and Predecessor Predecessor Combined

Predecessor

Nine Months Ended Nine Months Ended Nitrogen Fertilizer Year Ended December 31, September 30, September 30, Business ------------------------------ ------------------- --------------------- Financial Results 2001 2002 2003 2003 2004

(in millions)
Net sales $ 48.5 $ 58.5 $ 100.9 $ 71.7 $ 82.7 Gross margin 31.8 42.7 84.4 60.4 68.3 Operating expenses 60.1 70.7 59.6 42.4 44.0 Depreciation and 0.4 15.0 1.2 1.0 0.8 amortization
Operating income (52.5 ) (266.1 ) 7.8 4.8 18.1
(loss)
EBITDA (52.1 ) (251.1 ) 9.0 5.7 17.9 Adjusted EBITDA (33.3 ) (20.0 ) 14.7 11.4 19.3

Petroleum Business Results of Operations

Succesor and Predecessor Predecessor Combined Predecessor ------------------- ---------------------- ------------------------------ Nine Months Ended Nine Months Ended Year Ended December 31, September 30, September 30,
Market Indicators 2001 2002 2003 2003 2004

(dollars per barrel)
West Texas Intermediate
(WTI) crude oil $ 24.31 $ 25.33 $ 31.10 $ 30.77 $ 38.46 NYMEX 5-3-2 Crack
Spread $ 7.56 $ 5.68 $ 5.58 $ 6.13 $ 8.73 Crude Oil
Differentials:
WTI less WTS (sour) $ 2.81 $ 1.37 $ 2.75 $ 2.95 $ 3.91 WTI less Maya
(heavy sour) $ 8.85 $ 5.26 $ 6.95 $ 6.68 $ 12.00 WTI less Dated
Brent (foreign) $ 1.51 $ 1.11 $ 2.27 $ 2.32 $ 2.92 PADD 2 Group III versus
NYMEX Basis:
Gasoline $ 0.98 $ (0.16 ) $ 0.62 $ 0.64 $ (0.42 ) Heating Oil $ 2.06 $ 0.29 $ 0.52 $ 0.86 $ 1.55 Operating Statistics

(dollars per barrel)
Per barrel
margin/expense of crude
oil throughput:
Gross margin $ 5.12 $ 3.05 $ 3.89 $ 3.72 $ 5.92 Operating expense $ 3.36 $ 4.15 $ 2.63 $ 2.59 $ 2.65
(dollars per gallon)
Per gallon sales price:
Gasoline $ 0.86 $ 0.75 $ 0.91 $ 0.93 $ 1.17 Distillate $ 0.82 $ 0.71 $ 0.84 $ 0.84 $ 1.07

Succesor and Predecessor Predecessor Combined

Predecessor

Nine Months Ended Nine Months Ended Year Ended December 31, September 30, September 30, Selected --------------------------------------------------- ------------------- ----------------------- Volumetric Data 2001 2002 2003 2003 2004
Barrels Barrels Barrels Barrels Barrels Per Day % Per Day % Per Day % Per Day % Per Day %
Production:
Total 44,783 47.3 41,457 49.2 48,230 50.4 47,725 49.7 48,110 47.0 gasoline
Total 33,846 35.7 29,779 35.3 34,363 35.9 34,126 35.5 37,587 36.7 distillate
Total other 16,129 17.0 13,107 15.5 13,108 13.7 14,167 14.8 16,636 16.3 Total all 94,758 100.0 84,343 100.0 95,701 100.0 96,018 100.0 102,333 100.0 production
Crude oil 84,605 94.3 74,446 92.4 85,501 93.4 85,713 93.2 91,052 93.6 throughput
All other 5,122 5.7 6,109 7.6 6,085 6.6 6,215 6.8 6,200 6.4 inputs

Total 89,727 100.0 80,555 100.0 91,586 100.0 91,928 100.0 97,252 100.0 feedstocks

Succesor and Predecessor Predecessor Combined
Predecessor ------------------------------------------------------------ Nine Months Ended Nine Months Ended Year Ended December 31, September 30, 2003 September 30, 2004
Total Total Total Total Total Barrels % Barrels % Barrels % Barrels % Barrels %
Crude oil
throughput by
crude type:
Sweet 15,039,853 48.7 14,991,867 55.2 18,187,215 58.3 13,616,265 58.2 12,172,642 48.8 Light/medium
sour 15,440,430 50.0 9,902,688 36.4 12,311,203 39.4 9,318,197 39.8 12,775,690 51.2 Heavy sour 400,577 1.3 2,278,275 8.4 709,300 2.3 465,200 2.0 - - Total crude
oil throughput 30,880,860 100.0 27,172,830 100.0 31,207,718 100.0 23,399,662 100.0 24,948,332 100.0

Nine months ended September 30, 2004 compared to nine months ended September 30, 2003.

Net Sales. Petroleum net sales increased $286.4 million or 33%, to $1,151.9 million in the first nine months of 2004 from $865.5 million in the corresponding period in 2003. This revenue increase is attributable to increased production volumes and higher refined product prices, which reacted favorably to the increase in global crude oil prices over the period. The higher prices resulted in additional net sales of $224.0 million for the first nine months of 2004 over 2003. For the first nine months of 2004, crude oil throughput increased by an average of 5,339 bpd, or 5.9%, versus the comparable period in 2003. The higher crude throughput experienced in the first nine months of 2004 compared to 2003 was directly attributable to Farmland's inability, because of its impending reorganization, to purchase optimum crude oil blends necessary to operate the refinery at 2004 levels in 2003. For the first nine months of 2004, our petroleum business experienced increases in gasoline and distillate prices of 26% and 28%, respectively compared to the same period in 2003.

Gross Margin. Petroleum gross margin increased by $60.5 million, or 69%, to $147.8 million in the first nine months of 2004 from $87.3 million in the corresponding period of 2003. This increase was attributable to historically high differentials between refined products prices and crude oil prices as exemplified in the average NYMEX crack spread of $8.73 per barrel for the first nine months of 2004 and the increased discount for heavy crude oils demonstrated by the $5.32, or 80%, increase in the spread between the WTI price, which is a market indicator for the price of light sweet crude, and the Maya price, which an indicator for the price of heavy crude, in the nine months ended September 30, 2004 compared to the same period in 2003. The first nine months of 2004 also benefited from increased production volume versus the comparable period of 2003. Gross margin per barrel increased by $2.20, or 59%, to $5.92 in the first nine months of 2004 from $3.72 in the corresponding period in 2003.

Our gross margin for the nine months ending September 30, 2004 improved as a result of the termination of a single customer product marketing agreement in November 2003. During the first nine months of 2003 Farmland was party to a marketing agreement that required them to sell all refined products to a single customer at a fixed differential to an index price. Subsequent to the conclusion of the contract, we have expanded our customer base and increased the realized differential to that index. In addition, we have been able to supply value added fuels such as boutique blends for Kansas City and Denver markets that trade at a premium price to regular unleaded gasoline.

We blend light and heavy crude oil to create a medium gravity crude oil in order to utilize our refinery's coking capacity to derive economic benefit from the heavier crude. In 2004, we reduced the percent of light sweet WTI crude from 58.2% of the purchased crude in 2003 to 48.8%. Shifting from WTI crude to heavier crude has allowed us to take advantage of the wider spread between light and heavy crudes. In 2003 Farmland was restricted to one foreign cargo per month due to its bankruptcy. As a result, our ability to optimize our crude slate to take advantage of the discount associated with medium sour and medium heavy crudes resulting in a lower total crude charge rate as well as a lower discount to WTI was restricted.

Operating Expenses. Petroleum operating expenses increased by $5.7 million, or 9%, to $66.2 million in the first nine months of 2004 from $60.5 million in the corresponding period of 2003, primarily due to higher energy costs. Operating expense per barrel for the nine months ended September 30, 2003 and 2004 remained essentially constant at $2.59 in 2003 and $2.65 in 2004.

Depreciation and Amortization. Petroleum depreciation and amortization decreased by $0.5 million to $1.2 million in the first nine months of 2004 compared to the corresponding period in 2003. The decrease is primarily the result of the assets being revalued at a lower amount subsequent to the our acquisition.

Operating Income. Operating income increased $62.1 million, or 517%, to $74.2 million in the first nine months of 2004 from $12.1 million in the corresponding period in 2003. This increase was due to the factors discussed above, and particularly driven by favorable market conditions in the domestic refining industry.

Year ended December 31, 2003 compared to year ended December 31, 2002.

Net Sales. Petroleum net sales increased $332.3 million or 40%, to $1,161.3 million in 2003 from $829.0 million in 2002. This revenue increase is attributable to higher crude oil throughput of 85,501 barrels per day (bpd) in 2003 compared to 74,446 bpd in 2002, representing a 14.9% increase, and higher refined fuel pricing in 2003. Higher refined fuel prices contributed $164.6 million of the $332.3 million increase in revenue over this period. Gasoline price increases were the largest contributor, increasing 21% from $0.75 per gallon to $0.91 per gallon, contributing $102.5 million to the revenue increases. The price of distillate increased by 19% to $0.84 per gallon in 2003, as compared to $0.71 per gallon in 2002.

Increased crude throughput during 2003 compared to 2002 was primarily the result of a major maintenance turnaround at the refinery in March 2002, which halted production at the refinery for four weeks. Problems with the start up of the modified fluid catalytic cracking unit (FCCU) resulted in a delay in reaching normal operations for an additional two week period in 2002. In 2003, refined fuel production volume was 4.2 million barrels higher than 2002 resulting in a revenue increase of $157.7 million.

Gross Margin. Petroleum gross margin increased by $38.7 million, or 47%, to $121.3 million in 2003 from $82.6 million in 2002. The increase was primarily due to increased volume over 2002, as described above, during which a major turnaround at the refinery was completed. In addition, earnings were favorably impacted by an increase in the gross margin per barrel as a result of an improved pricing in our marketing region and a widening crude oil differential for heavy crude.

Crude oil throughput increased 15% to 31.2 million barrels in 2003 compared to 27.2 million barrels in 2002 resulting in a margin increase of approximately $15.7 million.

As demand in our marketing region increased by higher than historical rates, the price basis in the region increased relative to the NYMEX price by an average of $0.55 per barrel in 2003 over 2002 resulting in additional gross margin. In addition, the spread between WTI and heavy medium sour crude oils widened as indicated by the crude oil differentials. Both of these factors contributed to an improved gross margin per barrel in a time the NYMEX crack spread remained largely unchanged. The per barrel gross margin increased $0.84 to $3.89 in 2003 from $3.05 in 2002.

Operating Expenses. Petroleum operating expenses decreased by $30.6 million, or 27%, to $82.2 million in 2003 from $112.8 million in 2002. This decrease was principally attributable to expenses related to the major maintenance turnaround in March 2002 of approximately $17.0 million. This decrease in operating expenses was partially offset by higher usage of natural gas in 2003 as compared to 2002 due to increased throughput. Operating expense per barrel of total plant throughput decreased to $2.63 in 2003 from $4.15 in 2002.

Depreciation and Amortization. Petroleum depreciation and amortization decreased $13.7 million to $2.1 million in 2003 from $15.8 million in 2002 This change in depreciation and amortization is directly attributable to the $144.3 million impairment charge to reduce the carrying amount of the fixed assets of the petroleum business recorded in 2002, as more fully described in Note 3 to our financial statements included elsewhere in this prospectus.

Operating Income. Petroleum operating income increased by $205.4 million to $21.5 million in 2003 from an operating loss of $183.9 million in 2002. Excluding the reorganization expense associated

with the impairment of property, plant and equipment in 2002 of $144.3 million and $4.0 million in 2003, petroleum operating income increased by $65.1 million in 2003 versus 2002, primarily as a result of the reasons described above.

Year ended December 31, 2002 compared to year ended December 31, 2001.

Net Sales. Petroleum net sales decreased $752.7 million or 48%, to $829.0 million in 2002 from $1,581.7 million in 2001. This revenue decrease is primarily attributable to the sale of Country Energy as described above in "-Factors Affecting Comparability." In 2001, Farmland purchased and resold 6.7 million barrels of propane and 8.4 million barrels of gasoline and distillate from Country Energy. The revenue for this purchased product was not segregated, but we estimate the majority of the decrease in net sales was a result of the discontinuation of purchased products.

In addition to the impact of the sale of Country Energy, both lower volumes and lower prices impacted revenue in the petroleum business in 2002 compared to 2001. Our average sale price per gallon for gasoline and distillate decreased 12% and 13% respectively in 2002 as compared to 2001. Price decreases for gasoline and distillate, excluding the impact of volume purchased and resold, in 2002 versus 2001 negatively impacted revenue by $133.1 million.

Crude oil throughput declined to 74,446 bpd in 2002 compared to 84,605 bpd in 2001, which contributed significantly to lower revenue. Decreased crude throughput during 2002 compared to 2001 was primarily the result of a major maintenance turnaround at the refinery in March 2002, which halted production at the refinery for four weeks. Complications with the startup of the modified FCCU resulted in an additional two weeks of below normal operations in 2002.

Gross Margin. Petroleum gross margin decreased by $75.1 million, or 48%, to $82.6 million in 2002 from $157.7 million in 2001. The decrease was principally due to weak refining fundamentals as evidenced by a 25% reduction in the NYMEX crack spread from 2002 as compared to 2001. In addition to the general weakening of refinery economics, our consumed crude cost discount relative to WTI decreased in 2002 compared to 2001 as result of a declining differential for heavier more sour crude oil and a change in our crude oil mix from 49% light sweet crude in 2001 to 55% in 2002. The reason for lighter slate was a direct result of Farmland's bankruptcy and its inability to source more than one foreign cargo per month. Due to factors described gross margin per barrel in 2002 decreased 40% to $3.05 per barrel from $5.12 per barrel in 2001 resulting in a lower gross margin of $63.8 million dollars.

Total crude throughput declined by 3.7 million barrels in 2002 to 27.2 million barrels from 30.9 million barrels in 2001. The reduced barrels impacted gross margin by more than $11.3 million.

Operating Expenses. Petroleum operating expenses increased by $9.0 million or 9%, to $112.8 million in 2002 from $103.8 million in 2001 principally due to expenses associated with the major maintenance turnaround in March 2002 of approximately $17.0 million and increased environmental accruals of approximately $8.0 million. This increase in operating expenses compared to 2001 was partially offset by an overall reduction in costs associated with natural gas, production chemicals and catalyst. Operating expense per barrel increased $0.79 per barrel of plant throughput, or 24% to $4.15 in 2002 from $3.36 in 2001.

Equity in Earnings (Losses) of Joint Ventures. Results in 2001 reflect Farmland's loss in the joint venture interest of Country Energy, LLC of $2.8 million. This joint venture was sold to CHS in November 2001.

Depreciation and Amortization. Petroleum depreciation and amortization decreased $2.8 million, or 15%, to $15.8 million in 2002 from $18.6 million in 2001. This change in depreciation and

amortization is directly attributable to the $144.3 million impairment charge to reduce the carrying amount of the fixed assets of the petroleum business in 2002.

Operating Income. Petroleum operating income decreased $215.7 million in 2002 to an operating loss of $183.9 million in 2002 from operating income of $31.8 million in 2001. Excluding the reorganization expense associated with the impairment of property, plant and equipment in 2002 of $144.3 million and joint venture loss from Farmland's interest in Country Energy of $2.8 million, petroleum operating income decreased by $68.6 million in 2002 versus 2001.

Nitrogen Fertilizer Business Results of Operations

Predecessor and Successor Predecessor Combined

Nine Months Ended Nine Months Ended September 30, September 30,
2001 2002 2003 2003 2004 Market Indicators ----------- ----------- -------- ------------- ------------- Natural gas (dollars per million Btu) $ 4.26 $ 3.22 $ 5.36 $ 5.62 $ 5.81 Ammonia - southern plains (dollars per ton) 247 168 272 273 287 UAN - corn belt (dollars per ton) 144 108 141 139 162 Production (thousand tons):
Ammonia 198.5 265.1 335.7 244.4 233.0 UAN 286.2 434.6 510.6 363.8 378.1 Total 484.7 699.7 846.3 608.2 611.1 Sales (thousand tons):
Ammonia 86.1 85.3 134.8 92.7 88.6 UAN 246.3 450.0 528.9 387.8 384.8 Total 332.4 535.3 663.7 480.5 473.4 Product pricing (plant gate) (dollars per ton):
Ammonia $ 208 $ 147 $ 235 $ 233 $ 262
UAN 123 76 107 105 132
On-stream factor:
Gasification 66.8 % 78.6 % 90.1 % 89.7 % 91.2 % Ammonia 63.6 % 75.3 % 89.6 % 87.5 % 80.3 % UAN 66.8 % 78.6 % 81.6 % 79.1 % 80.3 % Capacity utilization:
Ammonia 49.5 % 66.0 % 83.6 % 81.4 % 77.3 % UAN 52.3 % 79.4 % 93.3 % 88.8 % 92.1 %

Nine months ended September 30, 2004 compared to nine months ended September 30, 2003.

Net Sales. Nitrogen fertilizer net sales increased $11.0 million or 15%, to $82.7 million in the first nine months of 2004 from $71.7 million in the corresponding period in 2003. The revenue increase was entirely attributable to increased nitrogen fertilizer prices, which more than offset a slight decline in total production volume due to a planned turnaround in August 2004. For the first nine months of 2004, southern plains ammonia and corn belt UAN prices increased 5% and 17%, respectively versus the comparable period in 2003. In addition, due to our direct marketing efforts, our actual netbacks relative to the market indices presented above have improved substantially. This improvement is the result of eliminating the reseller discount offered to Agriliance under the terms of the prior marketing agreement and maximizing shipments to customers that are more freight logical to our facility.

Operating Expenses. Nitrogen fertilizer operating expense increased by $1.6 million, or 4%, to $44.0 million in the first nine months of 2004 from $42.4 million in the corresponding period of 2003.

This increase was primarily due to the resumption of payments to our nitrogen and oxygen supplier, BOC, subsequent to the Transaction, the turnaround expense as discussed above, and an increase in costs allocated to the nitrogen fertilizer business for insurance.

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization decreased by $0.2 million, or 20%, to $0.8 million in the first nine months of 2004 from $1.0 million in the comparable period of 2003. This decrease was principally due to differences in the capitalized value of our nitrogen fertilizer plant in 2003 versus our allocation of the purchase price to the fixed assets of the nitrogen fertilizer plant completed in March 2004.

Operating Income. Operating income increased $13.3 million, or 277%, to $18.1 million in the first nine months of 2004 from $4.8 million in the corresponding period in 2003. This increase was due to continued strong market conditions in the domestic nitrogen fertilizer industry described above. For the 212 day period ending September 30, 2004 the nitrogen fertilizer business was charged $3.0 million for petroleum coke transferred from our refinery. During the Predecessor period, petroleum coke was transferred at zero value.

Year ended December 31, 2003 compared to year ended December 31, 2002.

Net Sales. Nitrogen fertilizer net sales increased $42.4 million or 72%, to $100.9 million in 2003 from $58.5 million in 2002. Prices accounted for $21.1 million of the revenue increase while the remaining $21.3 million was attributable to increased volume. In 2003, southern plains ammonia and corn belt UAN prices increased 62% and 31%, respectively versus 2002.

The remaining $21.3 million attributable to increased volume directly correlates to the improvement in operating days. The most significant factor was our increased gasifier on-stream time due to improvements in our operations and maintenance groups. Our ability to transition from our main gasifier to our spare gasifier without discontinuing ammonia production significantly reduced downtime.

Operating Expenses. Nitrogen fertilizer operating expenses decreased by $11.0 million, or 16%, to $59.6 million in 2003 from $70.7 million in 2002. The most significant factor in the decrease was $13.8 million reduction in depreciation expense as result of the asset impairment charge of $230.8 million in 2002, reductions in repairs and maintenance, reduced vendor fees associated with oxygen and nitrogen supply and lower payments made for royalties and operating assistance related to gasifier operations. This was offset by increased expenses for refractory brick and electricity.

Electricity costs increased $1.0 million due to a 5% increase in power usage in 2003 over 2002 as a result of the improved operating rates. Increased refractory brick costs in 2003 of $1.9 million resulted from replacing damaged brickwork in our gasifier.

The reduction in both oxygen and nitrogen supply payments and gasifier royalty and operating assistance payments resulted in Farmland's election to discontinue these payments subsequent to the bankruptcy filing. In both cases, resolutions were reached between Farmland and the counterparty and payments have already been made or agreed to by Farmland. These two items comprise approximately $1.8 million in cost improvements in 2003 compared to 2002.

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization decreased $13.8 million, or 91%, to $1.2 million from $15.0 million in 2002. This decrease in depreciation and amortization is directly attributable to the $230.8 million impairment charge to reduce the carrying amount of the fixed assets of the nitrogen fertilizer plant in 2002.

Operating Income. Nitrogen fertilizer operating income increased $273.9 million to $7.8 million in 2003 from a net loss of $266.0 million. Excluding the reorganization expense associated with the impairment of the nitrogen fertilizer plant in 2002 of $230.8 million and $5.8 million in 2003, operating

income increased by $46 million to $10.7 million in 2003 from an operating loss of $35.3 million in 2002, primarily for the reasons described above.

Year ended December 31, 2002 compared to year ended December 31, 2001.

Net Sales. Nitrogen fertilizer net sales increased by $10.0 million or 21%, to $58.5 million in 2002 from $48.5 million in 2001. Increased production volumes as a result of an increased on-stream factors at the nitrogen fertilizer plant in 2002 compared to 2001 resulted in a revenue increase of $15.6 million. The increase was offset by lower nitrogen prices. In 2002, Southern Plains ammonia and corn belt UAN prices decreased 32% and 25%, respectively versus 2001.

Operating Expenses. Nitrogen fertilizer operating expenses increased by $10.5 million, or 18%, to $70.7 million in 2002 from $60.1 million in 2001. This increase was the result of $14.6 million of additional depreciation expense offset by lower expenses of $3.6 million associated with the start-up and commissioning of the nitrogen fertilizer plant in 2001. Outside services decreased by $3.0 million in 2002 from 2001 primarily as a result of canceling our operating and maintenance agreement with Texaco to operate and maintain our gasifier.

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization increased $14.6 million to $15.0 million in 2002 from $0.4 million in 2001. This increase in depreciation and amortization was directly attributable to the capitalization of the fixed assets of the nitrogen fertilizer plant, which were previously reported as an operating lease. In February 2002, Farmland prepaid the outstanding balance of the operating lease, which financed the construction of our nitrogen fertilizer plant. This increase was offset by the impairment charge of $230.8 million later in 2002.

Operating Income. Nitrogen fertilizer operating income decreased $213.6 million in 2002 from an operating loss of $52.5 million in 2001. Excluding the reorganization expense associated with property, plant and equipment in 2002 of $230.8 million, nitrogen fertilizer operating income increased by $17.2 million in 2002 versus 2001. This increase was principally the result of improved on-stream factors at the nitrogen fertilizer plant offset by an overall reduction in nitrogen fertilizer prices in 2002 as compared to 2001.

Consolidated Results of Operations

Selling, General and Administrative Expenses. Consolidated selling, general and administrative expenses for the period from March 2, 2004 through September 30, 2004 were $8.4 million. These expenses represent the cost associated with corporate governance, legal expenses, treasury, accounting, marketing, human resources and maintaining corporate offices in New York and Kansas City. During the predecessor periods, Farmland allocated corporate overhead based on internal needs, which may not be representative of the actual cost to operate the businesses. In addition, during the nine months ended September 2003, Farmland incurred a number of charges related to the bankruptcy. As a result of the charges and issues related to allocations, a comparison of selling, general and administrative expenses for the nine months ended September 2004 to the nine months ended 2003 is not meaningful.

Interest Expense. For the Predecessor periods, all interest expense prior to May 31, 2002, and interest on secured borrowings subsequent to May 31, 2002 were allocated to the Predecessor by Farmland based on identifiable net assets of each of Farmland's divisions. Under bankruptcy law, payment of interest on Farmland's unsecured debt was stayed beginning May 31, 2002. Accordingly, Farmland did not allocate any interest on its unsecured borrowings to the Predecessor since May 31, 2002. Interest expense in the Successor period represents the interest recognized on our long-term borrowings and amortization of deferred financing costs associated with these borrowings.

Provision for Income Taxes. The Predecessor was not a separate legal entity, and its operating results were included with the operating results of Farmland and its subsidiaries in filing consolidated

federal and state income tax returns. Farmland did not allocate income taxes to its divisions. As a result, the Predecessor periods do not reflect any provision for income taxes.

Nine months ended September 30, 2004 compared to nine months ended September 30, 2003.

Net Income. Net income increased $35.8 million in the first nine months of 2004 to $51.0 million from $15.3 million for the comparable period in 2003. The increase was due to both the change in ownership and improved results in both the petroleum business and the nitrogen fertilizer business as discussed in greater detail for each business above.

Year ended December 31, 2003 compared to year ended December 31, 2002.

Other Income (Expense). Other expense was $0.2 million in 2003 compared to $4.1 million in 2002, primarily relating to changes in value of the Predecessor's derivative contracts.

Reorganization Expense; Impairment of Property Plant and Equipment. Reorganization expense represents the impairment of long-lived assets in accordance with the SFAS No. 144 implemented by Farmland. Recoverability of assets to be held and used is measured by comparison of the carrying amount of an asset to the estimated undiscounted future net cash flows expected to be generated by the asset. In 2003, Farmland determined the carrying amount of the assets of the petroleum and nitrogen fertilizer business exceeded the expected value to be received in a bankruptcy approved sale. As a result, an impairment charge of $9.6 million was recognized.

Net Income. Net income increased $493.6 million in 2003 to $27.9 million from a loss of $465.7 million in 2002. The asset impairment described above accounted for $365.4 million of the improvement. In addition, both facilities benefited from improved volumes, the nitrogen fertilizer market improved dramatically, the refined fuel price in the region improved and crude differentials improved.

Year ended December 31, 2002 compared to year ended December 31, 2001.

Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased by $8.4 million, or 34%, to $16.4 million in 2002 from $24.8 million in 2001. The decrease was principally the result of the dissolution of the Country Energy joint venture and the elimination of the Country Energy administrative fee, which was $9.1 million in 2001.

Equity in Loss of Joint Venture. In 2001, the Predecessor recognized $2.8 million in expenses related to its share of Country Energy's losses.

Reorganization Expense; Impairment of Property, Plant, and Equipment. The reorganization expense represents the impairment of long-lived assets in accordance with the SFAS No. 144 implemented by Farmland. Recoverability of assets to be held and used is measured by comparison of the carrying amount of an asset to the estimated undiscounted future net cash flows expected to be generated by the asset. In 2002, it was determined that the carrying amount of the assets of our petroleum and nitrogen fertilizer businesses exceeded their respective estimated future undiscounted net cash flows and, as a result, an impairment charge of $375.1 million was recognized.

Gain on Sale of Joint Venture Interest. Results in 2001 reflect the gain on the sale of Farmland's interest in Country Energy to CHS, Inc. in November 2001 for approximately $18.0 million.

Other Income (Expense). Other income (expense) decreased $5.6 million in 2002 to ($4.1) million, compared to $1.6 million of income in 2001, primarily related to the changes in value of the Predecessor's derivative contracts.

Net Income. Net income decreased $446.3 million in 2002 to a loss of $465.7 million from a loss of $19.4 million in 2001. The asset impairment described above accounted for $375.1 million of the decline. In addition, the crack spreads narrowed and the nitrogen fertilizer business experienced significantly lower prices.

Critical Accounting Policies

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides further information about our critical accounting policies and should be read in conjunction with the Notes to Financial Statements, which summarizes our significant accounting policies.

Major Maintenance Turnarounds. The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense as maintenance services are performed. During 2002, our refinery was shut down for approximately six weeks in order to perform planned major maintenance. Costs associated with this shutdown are included in costs of goods sold in 2002 and were approximately $17.0 million. Most refiners accrue for future planned turnarounds or defer the costs associated with turnarounds, which lessens the earnings impact in the year of the turnaround. As a result, comparison of our results to other refineries must take into account the impact of the difference in accounting for turnaround highlighted above. We expect that our next major maintenance will occur in 2006 at an estimated cost of approximately $12.0 million and $1.3 million for the petroleum business and nitrogen fertilizer business, respectively.

Impairment of Long-Lived Assets. During 2001, Farmland accounted for long-lived assets in accordance with Statement of Financial Accounting Standards No. 121, Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of (SFAS 121). SFAS 121 was superseded by SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144), which was adopted by Farmland effective January 1, 2002.

In accordance with both SFAS No. 144 and SFAS No. 121, Farmland reviewed its long-lived assets for impairment whenever events or changes in circumstances indicated that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimate undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeded its estimated future undiscounted net cash flows, an impairment charge was recognized by the amount by which the carrying amount of the assets exceeded the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying value or fair value less cost to sell, and are no longer depreciated.

In its Plan of Reorganization, Farmland stated, among other things, its intent to dispose of its petroleum and nitrogen assets. Despite this stated intent, these assets were not classified as held for sale under SFAS 144 until October 7, 2003 because, ultimately, any disposition must be approved by the Court and the Court did not approve such disposition until that date. Since Farmland determined that it was more likely than not that its assets would be disposed of, those assets were tested for impairment in 2002 pursuant to SFAS 144, using projected undiscounted net cash flows based on Farmland's best assumptions regarding the use and eventual disposition of those assets. Based on the tests, assumptions and determinations as of the impairment testing date, the assets were determined to be impaired. Farmland's best estimate at December 31, 2002 was that the carrying value of these assets exceeded the fair value expected to be received on disposition of these assets by approximately $375.1million. Accordingly, an impairment charge was recognized for such amount in 2002. The ultimate proceeds from disposition of these assets resulted from a bidding and auction process conducted in the bankruptcy proceedings. This process led to an additional impairment charge of $9.6 million recorded in September of 2003 when Farmland management's estimate was refined to reflect additional current information regarding the ultimate disposition of these assets.

Derivative Commodity Instruments. We use futures contracts, options, and forward contracts primarily to reduce our exposure to changes in crude oil prices and to provide economic hedges of inventory positions and forecasted transactions. Although management considers these derivatives economic hedges, these instruments have not been designated as hedges for accounting purposes and are recorded at fair value in the balance sheet. Accordingly, changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. Our petroleum business recorded net gains from derivative instruments of $0.9 million and $0.3 million in other income (expense) for the 212 days ended September 30, 2004 and the year ended December 31, 2003.

Environmental Expenditure. Liabilities related to remediation of contaminated properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. All liabilities are monitored and adjusted as new facts or changes in law or technology occur. Environmental expenditures are capitalized when such costs provide future economic benefits. Changes in laws, regulations or assumptions used in estimating these costs could have a material impact to our financial statements. The amount recorded for environmental obligations at September 30, 2004 totaled $9.8 million.

Purchase Price Accounting and Allocation. The transaction described in Note 1 to our financial statements related to the purchase of our assets from Farmland has been accounted for using the purchase method of accounting as of March 3, 2004. The allocation of the purchase price to the net assets acquired has been performed in accordance with SFAS 141, Business Combinations. In connection with the allocation of the purchase price, management used estimates and assumptions to determine the fair value of the assets acquired and liabilities assumed. Changes in these assumptions and estimates such as discount rates and future cash flows used in the appraisal process could have a material impact on how the purchase price was allocated at the date of acquisition.

Valuation of Our Equity. In connection with the Transaction, Coffeyville Group Holdings, LLC issued preferred and common units. The preferred units required a preference distribution of $63.2 million plus a preferred yield prior to any distribution to the residual interests, which was split 85% to the preferred and 15% to the common. Management determined the fair value of the equity based on the amount paid to Farmland in the Chapter 11 auction process less the amount borrowed. The fair value allocated to the preferred and common was estimated based on the estimated relative fair values on March 3, 2004. Changes in the assumptions used and the use of a different valuation technique could have a material impact on the financial statements.

Liquidity and Capital Resources

Our principal sources of liquidity are from cash and cash equivalents, cash from operations and borrowings under our senior secured credit agreement

Cash Balance and Other Liquidity

As of September 30, 2004, we had cash, cash equivalents and short-term investments of $13.0 million. Prior to March 3, 2004, Farmland centralized its cash management operations and did not segregate cash balances by business. We believe our September 30, 2004 cash levels as well as the availability of borrowings under our revolving credit agreement are adequate to fund our cash requirements for the foreseeable future. As of September 30, 2004, we had available up to $74.5 million under our revolving credit facility, which is discussed in more detail below.

Debt

Our current debt structure is used to fund our business operations, and our revolving credit facility is a source of liquidity. At September 30, 2004, our long-term debt, including current maturities, totaled $149.3 million. Debt outstanding under the term loan, and the revolving credit facility bore interest at variable rates. We also had capital lease obligations of $1.2 million at September 30, 2004.

On May 10, 2004, we completed a refinancing of substantially all of our outstanding long-term debt with a new $150.0 million senior secured term loan due in 2010 and a senior secured $75.0 million revolving credit facility which terminates in 2009. We used the net proceeds from the term loan to:

º •
º repay $34.3 million for all outstanding amounts under our then-existing revolving credit facility and term loan, including accrued and unpaid interest, fees and a $1.1 million make-whole premium to the previous lenders;

º •
º pay $9.3 million in costs associated with the refinancing that were capitalized and that will be amortized over the term of the new debt;

º •
º fund $6.4 million of cash into our operating account and a debt service account; and

º •
º distribute $100.0 million to shareholders for earnings distributions, preferred returns and return of capital.

The senior secured revolving credit facility provides for direct cash borrowings and the issuance of letters of credit up to the lesser of: (i) the borrowing base calculated with respect to our cash and eligible cash equivalents, eligible accounts receivables and eligible inventories, and
(ii) $75.0 million. Letters of credit issued under the revolving loans are subject to an issuance sub-limit of $30.0 million. After May 2006, the issuance sub-limit will increase to $50 million. As of September 30, 2004, we had $3.1 million of standby letters of credit issued and outstanding under this facility. Borrowings under the revolving loans are secured by a first priority security interest in our accounts receivable and inventory and contract rights, chattel paper, instruments, documents, deposit accounts and intangible assets related thereto. We had $71.9 million of available borrowing capacity at September 30, 2004 under the credit agreement. The $75.0 million senior secured revolving loans bear interest at either LIBOR plus 3.00%, or prime rate plus 1.00% subject to a 0.5% per annum unused capacity commitment fee. We had outstanding borrowings of $72,000 at September 30, 2004 under the senior secured facility.

The senior secured term loan is subject to quarterly principal amortization of payments of approximately $0.4 million that began on June 30, 2004 with the balance due at maturity in 2010. Mandatory prepayments are required to be made with the proceeds of certain asset sales and casualty events subject, in some instances, to reinvestment provisions. In addition, the senior secured credit facility also requires prepayment of any outstanding balance subject to excess cash flow provisions as determined under the credit agreement. The senior secured term loan is secured by a first priority lien on all our property, plant and equipment as well as a second priority lien on the primary collateral of the senior secured revolving loans. The senior secured term loan bears interest at LIBOR plus 5.00%, or at the prime rate plus 4.00%. The interest rate on the term loan at September 30, 2004 was 6.95%.

Under the credit agreement and subject to a prepayment penalty, we may prepay all or part of the senior secured term loans. The prepayment penalty is calculated as a declining percentage of the total senior secured term debt or senior secured revolving commitment retired. The prepayment penalty is dependent upon the actual date the prepayment occurs. No prepayment penalties exist for the senior revolving loans and the senior secured term loan after May 10, 2006 and May 10, 2007, respectively.

The credit agreement contains customary covenants and events of default. Accordingly, this agreement imposes significant operating and financial restrictions on us. These restrictions, among other things, limit incurrence of additional indebtedness, payment of dividends, significant investments

and sales of assets. These limitations are subject to a number of important qualifications and exceptions.

The credit agreement requires us to maintain specified financial ratios as follows:

º •
º Minimum Fixed Charge Ratio of 1.25 to 1.00;

º •
º Maximum Leverage Ratio of 3.50 to 1.00; and

º •
º Minimum Interest Coverage Ratio of 2.00 to 1.00.

In addition, the credit agreement limits the amount of capital spending (as defined therein) to $35.0 million, $45.0 million and $60.0 million in 2004, 2005 and 2006 respectively and $30.0 million for each year after 2006. The provision limiting this capital spending allows for flexibility in the timing of the expenditure.

For all calendar years through and including 2007, subject to meeting certain employment levels which we currently exceed, we are abated from any ad valorem real estate and personal property tax liability on our nitrogen fertilizer assets that were part of the original construction of the facility. Beginning in 2008, we will be subject to ad valorem real estate and personal property taxes on the facility at the then applicable rate on the assessed value to be determined by the county appraiser. The actual amount cannot be determined until an assessed value for the assets is established.

Capital Spending

We divide our capital spending needs into two categories, non-discretionary, which is either capitalized or expensed, and discretionary, which is capitalized. Non-discretionary capital spending, such as for planned turnarounds and other maintenance, is required to maintain safe and reliable operations or to comply with environmental, health and safety regulations. We estimate that our total non-discretionary capital spending needs, including turnaround expenditures, will be approximately $56 million in 2005, approximately $71 million in 2006 and approximately $84 million in the aggregate over the three-year period beginning 2007. These estimates include the capital costs necessary to comply with environmental regulations, including Tier II gasoline standards and on-road diesel regulations.

We estimate that compliance with the Tier II gasoline and on-road diesel standards will require us to spend approximately $34 million in 2005, approximately $43 million in 2006, approximately $20 million during 2008 and 2009 and an additional $15 million thereafter. See "Business-Environmental Matters-The Clean Air Act-Fuel Regulations-Tier II, Low Sulfur Fuels."

The following table sets forth our estimate of our non-discretionary capital spending for the years presented:

Cumulative 2005 2006 2007 2008 2009 Through 2009

(in millions)
Environmental capital needs $ 36.5 $ 45.8 $ 3.0 $ 13.2 $ 33.0 $ 131.4 Sustaining capital needs 19.7 11.6 11.3 11.6 10.0 64.2 Planned turnaround capital needs - 13.3 - 1.6 - 14.9 Total estimated capital needs $ 56.2 $ 70.6 $ 14.2 $ 26.4 $ 43.0 $ 210.4

We undertake capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in operating costs. As of December 31, 2004, we had committed approximately $13.7 million towards discretionary capital spending in 2005.

Cash Flows

Operating Activities

Nine months ended September 30, 2004 compared to nine months ending September 30, 2003.

Operating activities generated $98.0 million in the first nine months of 2004 versus $35.4 million for the comparable period in 2003. The $62.6 million improvement in operating cash flow was due to a $36.3 million improvement in net income and favorable changes in working capital. For purposes of this cash flow discussion, we define working capital as accounts receivable, inventories, prepaids and other assets less accounts payable, other current liabilities and deferred revenue. Changes in components of working capital generated $32.3 million of cash flow in the first nine months of 2004, compared to cash generated in the comparable period of 2003 of $0.8 million, an increase of $31.5 million. In the first nine months of 2004, accounts receivable increased $11.2 million and inventory increased by $13.2 million. The resulting effect on operating cash flows was offset by an increase in accounts payable of $26.1 million due to price increases and a returning to normal payment terms with some vendors, an increase in accrued liabilities of $9.8 million and a $17.4 million decrease in prepaids and other. The primary source for the $35.4 million in cash flow generated in the first nine months of 2003 was $32.0 million of cash flow generated from net income. This amount was adjusted for the $9.6 million impairment of property, plant and equipment charge resulting from the sales price of the petroleum assets and a $7.0 million increase in a long-term environmental accrual.

Year ended December 31, 2003 compared to year ended December 31, 2002.

Operating activities generated $20.3 million in 2003 compared to a use of cash of $1.7 million in 2002. The $22.0 million improvement in cash flows was due to a $128.2 million improvement in income from operations, as adjusted for the impairment charges of $375.1 million in 2002 and $9.6 million in 2003, offset by unfavorable changes in working capital. Changes in components of working capital used cash of $28.5 million in 2003, compared to $52.6 million of cash provided in 2002, an increase of $81.1 million. In 2003, accounts receivable increased by $25.3 million due to higher average selling prices and an increase in volume from the nitrogen fertilizer segment, while prepaid and other current assets increased by $23.8 million as a result of both increases in the price and volume of prepaid crude oil. The resulting effect on operating cash flows was offset by an increase in accounts payable of $8.3 million due to price increases and returning to normal payment terms with some vendors as time had elapsed from the bankruptcy of Farmland and a $10.4 million dollar decrease in inventory primarily as a result of lower raw material prices. The primary reason for the $52.6 million source of cash in components of working capital for 2002 was a $56.2 million increase in accounts payable as result of the bankruptcy filing of Farmland and the suspension of terms by nearly all of Farmland's raw material suppliers.

Year ended December 31, 2002 compared to year ended December 31, 2001.

Operating activities produced a cash outflow of $1.7 million in 2002 compared operating cash flow generation of $65.4 million in 2001. The decrease of $67.1 million was primarily due to two substantial events. In 2002, Farmland filed bankruptcy, which resulted in an increase in the accounts payable of $56.2 million due to the suspension of paying pre-petition liabilities subject to compromise. In 2001, working capital was impacted by the dissolution of Cooperative Refining, LLC on December 31, 2000. On that date, Farmland purchased excess inventory from Cooperative Refining of $59.7 million resulting in an increase in the working capital position as of December 31, 2000. The excessive working capital position was liquidated in 2001, resulting in cash generation from working capital.

Investing Activities

Nine months ended September 30 2004 compared to nine months ended September 30, 2003.

Net cash used in investing activities for the nine month period ending September 30, 2004, was $127.1 million as compared to $0.8 million for the comparable period of 2003. This difference is directly attributable to an increase in capital expenditures and the acquisition of the Farmland assets during the comparable periods. For the nine months ending September 30, 2003 and throughout its bankruptcy, Farmland's management maintained capital expenditures on the petroleum and nitrogen assets to a minimum.

Year ended December 31, 2003 compared to years ended December 31, 2002 and 2001.

Net cash from investing activities was a use of $0.8 million in 2003 compared to a use of $272.4 million in 2002 and a source of $17.9 million in 2001. Capital expenditures accounted for $0.8 million, $12.2 million and $8.2 million, in 2003, 2002 and 2001, respectively. These capital expenditures were related to operational improvements, maintenance capital, safety and environmental related projects. In 2002, an additional $260.3 million was spent acquiring the nitrogen fertilizer complex that had previously been financed under an operating lease arrangement. In 2001, asset sales related to the sale of Farmland's interest in the Country Energy, LLC and Farmland's interest in a propane business generated cash proceeds of $18.9 million and $7.2 million, respectively.

Financing Activities

Nine months ending September 30, 2004 compared to the nine months ended September 30, 2003.

Net cash used by financing activities in the nine month period ending September 30, 2004 was $42.0 million. The uses of cash for financing activities over this period related primarily to the prepayment of the $22.7 million term loan, a $100.0 million cash distribution to the holders of the preferred and common units issued by Coffeyville Group Holdings, LLC, $16.2 million in financing costs and $53.2 million in net divisional equity distribution to Farmland. We used cash from operations and a new term loan for $150.0 million completed on May 10, 2004 to finance the aforementioned cash outflows in 2004. For the nine month period ending September 30, 2003, we used $34.6 million in cash to fund a net divisional equity distribution.

Year ended December 31, 2003 compared to years ended December 31, 2002 and 2001.

For the 2003, 2002 and 2001, the petroleum and nitrogen fertilizer businesses were financed by the parent company. All cash generated or used was immediately disbursed to the parent, Farmland, in the form of a net divisional equity distribution or contribution. Neither the petroleum business nor the fertilizer business had incremental access to capital beyond that available from Farmland.

Capital and Commercial Commitments

In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of September 30, 2004 relating to long-term debt and unconditional purchase obligations and operating leases for the quarter ending December 31, 2004, the five-year period following December 31, 2004 and thereafter.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash flow in the future. This, to a certain extent, is subject to general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Based on our current level of operations, we believe our cash flow from

operations, available cash and available borrowings under our revolving credit facility will be adequate to meet our future liquidity needs for the foreseeable future.

Payments Due by Period

Quarter Ending December 31, Total 2004 2005 2006 2007 2008 2009 Thereafter
(in millions)
Contractual Obligations
Long-term debt (1) $ 149.3 $ 0.4 $ 1.5 $ 1.5 $ 1.5 $ 1.5 $ 1.5 $ 141.4 Capital lease 1.2 1.2 - - - - - - Operating leases (2) 16.3 0.7 3.3 3.1 2.9 2.9 1.9 1.5 Unconditional purchase
obligations (3) 176.6 1.4 12.8 12.8 12.8 8.8 8.8 119.1 Other long-term
liabilities included in
the
balance sheet (4) 2.1 0.3 1.0 0.8 - - - - Environmental liabilities
(5) 15.6 0.8 0.8 0.6 0.5 2.6 3.6 6.7 Interest payments (6) 56.6 2.6 10.3 10.3 10.1 10.0 9.9 3.4 Total $ 417.7 $ 7.4 $ 29.7 $ 29.1 $ 27.8 $ 25.8 $ 25.7 $ 272.2 Other Commercial Commitments
Standby letters of credit
(7) $ 3.1 $ - $ 3.1 $ - $ - $ - $ - $ -

º (1)
º Long-term debt amortization is based on the contractual terms of our credit agreement.

º (2)
º We lease various facilities and equipment, primarily railcars for our nitrogen fertilizer business under noncancelable operating leases for various periods.

º (3)
º The amount includes (1) commitments under a pipeline construction, operation and transportation agreement related to the delivery of crude oil from Cushing, Oklahoma to our Broom Station pipeline system near Caney, Kansas and (2) commitments under an electric supply agreement.

º (4)
º The amount includes contractual payments due to Farmland related to rejection damages for the electricity contract with the City of Coffeyville.

º (5)
º Environmental liabilities represents our estimated payments required by Federal and/or state environmental agencies related to sites in Coffeyville and Phillipsburg, Kansas.

º (6)
º Interest payments are based on interest rate in effect at September 30, 2004 and assume contractual amortization payments.

º (7)
º Standby letters of credit include our obligations under $3.1 million of letters of credit issued in connection with environmental liabilities.

Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our revolving credit facility in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.

Off-Balance Sheet Arrangements

As of September 30, 2004, we had several operating lease agreements with payments due on a monthly, quarterly or annual basis. The primary assets financed under these agreements were railcars utilized in the delivery of finished products for the nitrogen fertilizer business. For the period ending September 30, 2004, we had approximately 590 railcars subject to three separate lease agreements.

Quantitative and Qualitative Disclosures About Market Risk

The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. None of our market risk sensitive instruments are held for trading.

Commodity Risk

Impact of Changing Prices. Our revenues and cash flows, as well as estimates of future cash flows, are very sensitive to changes in energy prices. Major shifts in the cost of crude oil and the price of refined products and natural gas can result in large changes in the operating margin from refining operations. These prices also determine the carrying value of our refinery's inventories.

Our revenues, cash flows and estimates of future cash flows related to the fertilizer business are sensitive to changes in nitrogen fertilizer prices, which have shown strong correlation to natural gas prices.

Price Risk Management Activities. At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions that are in excess of our base level of operating inventories, to fix margins on certain future production and fix differentials on crude oil. The commodity derivative contracts we use may take the form of futures contracts or price swaps and are entered into with reputable counterparties. We account for our commodity derivative contracts under mark-to-market accounting, and gains or losses on commodity derivative are recognized in other (income) expense in the period incurred.

At September 30, 2004, we had the following open commodity derivative contracts whose unrealized gains or losses are included in other (income) expense in the consolidated statements of operations:

º •
º Derivative contracts on 80,000 barrels of heating oil crack spreads, the price spread between crude oil and heating oil, to fix the margin on forecasted sales in October and November 2004. These open contracts had total unrealized net losses at September 30, 2004 of approximately $82,000.

º •
º Derivative contracts on 870,000 barrels of unleaded gasoline crack spreads, the price spread between crude oil and unleaded gasoline, to fix the margin on forecasted sales in October, November and December 2004. These open contracts had total unrealized net gains at September 30, 2004 of approximately $298,000.

As of September 30, 2004, a $1.00 change in quoted futures price for the crack spreads described above would result in a $950,000 change to the fair market value of the derivative commodity position and the same change in operating income.

During the nine months ended September 30, 2004 we utilized additional derivative contracts on unleaded gasoline crack spreads and heating oil crack spreads to fix the refining margin to the NYMEX spread between light crude oil contract price and unleaded gasoline and heating oil price for a portion of forecasted refined products production. During the nine months ended September 30, 2004, we recorded realized losses of nearly $1.0 million (included in other income (expense)) on these contracts. These losses are in addition to the unrealized gains and losses on open positions described above.

Interest Rate Risk

Borrowings under our term loan and revolving credit facility bear a current market rate of interest such that we are subject to interest rate risk on these borrowings. As of September 30, 2004, a 100 basis point change in interest rates on our floating rate loans, which totaled $149.3 million, would result in a $1.5 million change in pretax income on an annual basis.

INDUSTRY OVERVIEW

Oil Refining Industry

Oil refining is the process of separating the wide spectrum of hydrocarbons present in crude oil, and in certain processes, modifying the constituent molecular structures, for the purpose of converting them into marketable finished petroleum products optimized for specific end uses. According to the Energy Information Association, as of January 1, 2004, there were 147 oil refineries operating in the U.S., with the 16 smallest each having a capacity under 13,000 bpd, and the 12 largest having capacities ranging from 300,000 to 550,000 bpd.

The current refining industry is characterized by capacity shortage, high utilization rates, and reliance on imported products to meet the demand for finished petroleum products. The last major oil refinery in the U.S. was built in 1976. Over the past three decades, more than 150 generally small and unsophisticated refineries that were unable to process heavy crude into a marketable product mix were permanently closed down. According to the Energy Information Association, while domestic refining capacity has decreased 1.5%, from 6.5 billion barrels in 1983 to 6.4 billion barrels in 2003, domestic demand for refined fuels has increased 30.4%, from 5.6 billion barrels to 7.3 billion barrels over the same period.

The following overview explains the basics of the refining process and certain factors that influence the refining industry.

Refining Basics

Refineries are uniquely designed to process and convert crude oils having a specific range of characteristics into the products required by the market of interest. In general, the different process units inside a refinery perform one of three functions:

Distillation: Separating the many types of hydrocarbons present in crude oil into distinct hydrocarbon fractions with specific boiling point ranges, such as gasoline, diesel oil and heavier hydrocarbons. Atmospheric and vacuum distillation are the primary distillation processes;

Conversion: Chemically changing the various hydrocarbon fractions into more desirable products by (a) rearranging the molecular structure through catalytic reforming, (b) creating larger, useable fractions from highly volatile light components through alkylation and isomerization, and/or (c) catalytically or thermally breaking down low value, very high molecular weight fractions into lighter gasoline and distillate range materials through fluid catalytic cracking and delayed coking; and

Treating: Removing unwanted contaminant elements and compounds such as sulfur, nitrogen, metals, and aromatics, typically via hydrotreating and contaminant recovery.

Each step in the refining process is designed to maximize the product realization for each level of the feedstocks, particularly the crude oil, processed through the refinery.

Typically, the first step in the refining process is to remove any chloride and solid impurities from the crude oil that would prove to be destructive to the downstream refining processes. This is accomplished in a water washing process called desalting.

The desalted crude oil is then processed through an atmospheric distillation unit where it is separated into various components based on the boiling ranges. Two principal side streams are withdrawn, a naphtha fraction whose boiling point range is similar to that of gasoline and the next heavier fraction, a middle distillate cut whose boiling point is similar to those of diesel oil and heating oil. The temperature at the bottom of the atmospheric distillation tower is held at approximately 650 degrees Fahrenheit since the non volatilized tower bottoms would thermally degrade at temperatures

above that level. Atmospheric distillation tower bottoms, generally referred to as atmospheric residuum or long residuum, is that part of the crude oil that is not volatile at 650 degrees Fahrenheit. Atmospheric residuum still contains valuable fractions, which are processed through a vacuum distillation tower, which allows, by virtue of the vacuum conditions, the useable hydrocarbons to distill off at actual temperatures that do not exceed the degradation point, but simulate the theoretical separation that would occur at a 1050 degree boiling point. The principal side stream is a vacuum gas oil (VGO) that becomes further upgraded in the refinery as it is charged to the fluid catalytic cracking unit. The non-volatilized bottoms of the vacuum unit are generally referred to as vacuum tower bottoms (VTBs) or asphaltic residuum.

Our Refinery Configuration

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The next step in the refining process is to convert the major hydrocarbon fractions into distinct and marketable products. These major fractions include the naphtha and mid-distillate streams from the atmospheric distillation unit, and the VGO and VTBs fractions from the vacuum distillation unit. The VGO stream is processed in a fluid catalytic cracker (FCC) where it is chemically altered to produce fractions that boil in the mid-distillate and gasoline boiling range. Some of the material produced in the FCC is not of adequate quality to directly produce gasoline and mid-distillate fuels, and cannot be recycled, so these intermediates are withdrawn from the FCC and fed to the delayed coker for further upgrading to a finished product. The VTBs, a very heavy tar, is processed through a delayed coking unit where it is exposed to high temperature and moderate pressure for long time periods. During that process, the vacuum residuum is thermally fractionated into naphtha, distillate and gas oil streams that get further upgraded to finished products, and to a solid coke byproduct. The most important conversion units in this refinery are the delayed coking unit and the fluid catalytic cracking unit, which combine to convert heavy crude oil into gasoline and diesel oil range products.

The light end products from the delayed coking unit and FCC are upgraded into high octane, low volatility, low aromaticity blend stocks in an alkylation unit catalyzed with hydrofluoric acid.

The light portion of the naphtha is separated and processed in an isomerization unit. In this unit the straight chain molecules are converted into branched chain molecules that have more valuable blending properties.

Both the virgin heavy naphthas that are produced directly from the crude oil as well as the cracked naphthas produced by the coker and the FCC are upgraded to gasoline in the catalytic reformer where molecular structure is substantially rearranged, creating octane value in the gasoline pool, and generating the hydrogen needed in the refinery to reduce the sulfur content of the product pool.

Refinery Products

Major refinery products include:

Gasoline. The most significant refinery product is motor gasoline. The most important product characteristics of gasoline include octane level (high levels of which command a premium), vapor pressure and sulfur content. Various gasoline blendstocks are blended to achieve specifications for regular and premium grades in both summer and winter gasoline formulations. Refiners also produce different grades of reformulated gasoline from time to time as required by their markets. Reformulated gasolines are special blends containing oxygenates, which contain ethers such as Methyl Tertiary Butyl Ether or, more frequently, ethyl alcohol. These formulations are tailored to areas of the country with severe ozone pollution.

Distillate Fuels. Distillates are diesel fuels and domestic heating oils. The most important characteristic of diesel fuel is its cetane number, analogous, but diametrically opposite to octane number in gasoline, and sulfur content. As with gasoline, the market pays a premium for high cetane fuels, but unlike gasoline, there is a two tier sulfur content market