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•	a crude oil gathering system with a gathering capacity of approximately 60,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, which is supported by approximately 336 miles of owned and leased pipelines;

•	a 170,000 bpd pipeline system that transports crude oil to the Coffeyville refinery and over 6.0 million barrels of owned and leased crude oil storage capacity;

•	a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and to customers at throughput terminals on Magellan Midstream Partners, L.P. ("Magellan") and NuStar Energy, LP's ("NuStar") refined products distribution systems; and

•	combined refinery related storage capacity of approximately 4.5 million barrels.

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Crude Oil Gathering System.  The petroleum business owns and operates a crude oil gathering system serving Kansas, Nebraska, Oklahoma, Missouri and Texas. The system has field offices in Bartlesville and Pauls Valley, Oklahoma and Plainville, Winfield and Iola, Kansas. The gathering system includes approximately 336 miles of owned and leased pipelines and approximately 150 crude oil transports and associated storage facilities, which allows it to gather crude oils from independent crude oil producers. The crude oil gathering system has a gathering capacity of approximately 60,000 bpd. Gathered crude oil provides an attractive and competitive base supply of crude oil for the Coffeyville and Wynnewood refineries. During 2014, the petroleum business gathered an average of approximately 59,000 bpd. The petroleum business also has 35,000 bpd of contracted capacity on the Keystone and Spearhead pipelines that allow it to supply price-advantaged Canadian and Bakken crudes to its refineries. By the third quarter of 2015, the petroleum business' contracted capacity will expand by approximately 6,700 bpd through new capacity on the Pony Express and White Cliffs pipelines, which will provide it with additional supplies of Bakken and Niobrara crudes to its refineries.

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Pipelines and Storage Tanks.  The petroleum business owns a proprietary pipeline system capable of transporting approximately 170,000 bpd of crude oil from its Broome Station facility located near Caney, Kansas to its Coffeyville refinery. Crude oils sourced outside of the proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to the Broome Station tank farm via a pipeline owned by Plains Pipeline L.P. ("Plains"). The petroleum business owns approximately (i) 1.4 million barrels of crude oil storage capacity that supports the gathering system and the Coffeyville refinery, (ii) 0.9 million barrels of crude oil storage capacity at the Wynnewood refinery and (iii) 1.0 million barrels of crude oil storage capacity in Cushing, Oklahoma. The petroleum business also leases additional crude oil storage capacity of approximately 2.8 million barrels in Cushing and approximately 0.1 million barrels at the Wynnewood refinery. In addition to crude oil storage, the petroleum business owns approximately 4.5 million barrels of combined refinery related storage capacity.

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•	restrictions on operations or the need to install enhanced or additional controls;

•	the need to obtain and comply with permits, licenses and authorizations;

•	requirements for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and liability for off-site waste disposal locations; and

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•	specifications for the products marketed by the petroleum business and the nitrogen fertilizer business, primarily gasoline, diesel fuel, UAN and ammonia.

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•	the volumes of its actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement;

•	accidents, interruptions in transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect its refinery or suppliers or customers;

•	the counterparties to its futures contracts fail to perform under the contracts; or

•	a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.

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•	denial or delay in obtaining regulatory approvals and/or permits;

•	unplanned increases in the cost of equipment, materials or labor;

•	disruptions in transportation of equipment and materials;

•	severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting the petroleum business' facilities, or those of its vendors and suppliers;

•	shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

•	market-related increases in a project's debt or equity financing costs; and/or

•	nonperformance or force majeure by, or disputes with, the petroleum business' vendors, suppliers, contractors or sub-contractors.

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Although we believe the petroleum business has sufficient liquidity under its ABL credit facility and the intercompany credit facility to operate both the Coffeyville and Wynnewood refineries, and that the nitrogen fertilizer business has sufficient liquidity under its revolving credit facility to run the nitrogen fertilizer business, under extreme market conditions there can be no assurance that such funds would be available or sufficient, and in such a case, we may not be able to successfully obtain additional financing on favorable terms, or at all. Furthermore, the nitrogen fertilizer business' credit facility matures in April 2016 and there can be no assurance that it will be able to refinance its $125.0 million of outstanding term loan debt or obtain a new revolving credit facility on similar terms or at all.

•	Market volatility could exert downward pressure on the price of the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units, which may make it more difficult for either or both of them to raise additional capital and thereby limit their ability to grow, which could in turn cause our stock price to drop.

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The petroleum business' and nitrogen fertilizer business' credit facilities contain various covenants that must be complied with, and if either business is not in compliance, there can be no assurance that either business would be able to successfully amend the agreement in the future. Further, any such amendment may be expensive. In addition, any new credit facility the petroleum business or nitrogen fertilizer business may enter into may require them to agree to additional covenants.

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•	Market conditions could result in significant customers experiencing financial difficulties. We are exposed to the credit risk of our customers, and their failure to meet their financial obligations when due because of bankruptcy, lack of liquidity, operational failure or other reasons could result in decreased sales and earnings for us.

•	major unplanned maintenance requirements

•	catastrophic events caused by mechanical breakdown, electrical injury, pressure vessel rupture, explosion, contamination, fire, or natural disasters, including, floods, windstorms and other similar events;

•	labor supply shortages, or labor difficulties that result in a work stoppage or slowdown;

•	cessation or suspension of a plant or specific operations dictated by environmental authorities; and

•	an event or incident involving a large clean-up, decontamination, or the imposition of laws and ordinances regulating the cost and schedule of demolition or reconstruction, which can cause significant delays in restoring property to its pre-loss condition.

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•	unforeseen difficulties in the integration of the acquired operations and disruption of the ongoing operations of our business;

•	failure to achieve cost savings or other financial or operating objectives contributing to the accretive nature of an acquisition;

•	strain on the operational and managerial controls and procedures of the petroleum business and the nitrogen fertilizer business, and the need to modify systems or to add management resources;

•	difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;

•	assumption of unknown material liabilities or regulatory non-compliance issues;

•	amortization of acquired assets, which would reduce future reported earnings;

•	possible adverse short-term effects on our cash flows or operating results; and

•	diversion of management's attention from the ongoing operations of our business.

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•	a significant portion of their cash flows could be used to service their indebtedness, reducing available cash and their ability to make distributions on their common units (including distributions to us);

•	a high level of debt would increase their vulnerability to general adverse economic and industry conditions;

•	the covenants contained in their debt agreements will limit their ability to borrow additional funds, dispose of assets, pay distributions and make certain investments;

•	a high level of debt may place them at a competitive disadvantage compared to competitors that are less leveraged and who therefore may be able to take advantage of opportunities that their indebtedness would prevent them from pursuing;

•	their debt covenants may also affect flexibility in planning for, and reacting to, changes in the economy and in their industries;

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•	a high level of debt may make it more likely that a reduction in the petroleum business' borrowing base following a periodic redetermination could require the Refining Partnership to repay a portion of its then-outstanding bank borrowings under its ABL credit facility; and

•	a high level of debt may impair their ability to obtain additional financing in the future for working capital, capital expenditures, debt service requirements, acquisitions, general corporate or other purposes.

•	their future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control; and

•	the Refining Partnership's ability to borrow under its Amended and Restated ABL Credit Facility and the intercompany credit facility between the Refining Partnership and us, and the Nitrogen Fertilizer Partnership's ability to borrow under its revolving credit facility, the availability of which depends on, among other things, compliance with their respective covenants.

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•	incur, assume or guarantee additional debt or issue redeemable or preferred units

•	make distributions or prepay, redeem, or repurchase certain debt;

•	enter into agreements that restrict distributions from restricted subsidiaries;

•	incur liens;

•	sell or otherwise dispose of assets, including capital stock of subsidiaries;

•	enter into transactions with affiliates; and

•	merge, consolidate or sell substantially all of their assets.

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•	the election and appointment of directors;

•	business strategy and policies;

•	mergers or other business combinations;

•	acquisition or disposition of assets;

•	future issuances of common stock, common units or other securities;

•	incurrence of debt or obtaining other sources of financing; and

•	the payment of dividends on the Company's common stock and distributions on the common units of the Refining Partnership and the Nitrogen Fertilizer Partnership.

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•	the requirement that a majority of our board of directors consist of independent directors;

•	the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors; and

•	the requirement that we have a compensation committee that is composed entirely of independent directors.

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•	preferred stock that could be issued by our board of directors to make it more difficult for a third party to acquire, or to discourage a third party from acquiring, a majority of our outstanding voting stock;

•	limitations on the ability of stockholders to call special meetings of stockholders;

•	limitations on the ability of stockholders to act by written consent in lieu of a stockholders' meeting; and

•	advance notice requirements for nominations of candidates for election to our board of directors or for proposing matters that can be acted upon by our stockholders at stockholder meetings.

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•

The partnership agreements permit each partnership's general partner to make a number of decisions in its individual capacity, as opposed to its capacity as general partner. This entitles its general partner to consider only the interests and factors that it desires, and means that it has no duty or obligation to give any consideration to any interest of, or factors affecting, any limited partner.

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The partnership agreements provide that each partnership's general partner will not have any liability to unitholders for decisions made in its capacity as general partner so long as (i) in the case of the Nitrogen Fertilizer Partnership, it acted in good faith, meaning it believed that the decision was in the best interest of the Nitrogen Fertilizer Partnership and (ii) in the case of the Refining Partnership, it did not make such decisions in bad faith, meaning it believed that the decisions were adverse to the Refining Partnership's interests.

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The partnership agreements provide that each partnership's general partner and the officers and directors of its general partner will not be liable for monetary damages to common unitholders, including us, for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that (i) in the case of the Nitrogen Fertilizer Partnership, the general partner or its officers or directors acted in bad faith or engaged in fraud or willful misconduct, or in, the case of a criminal matter, acted with knowledge that the conduct was criminal and (ii) in the case of the Refining Partnership, such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or with respect to any criminal conduct, with the knowledge that its conduct was unlawful.

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(1)	The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO).

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(1)	We acquired WEC on December 15, 2011 and its results of operations are included from the date of acquisition.

(2)	Amounts are shown exclusive of depreciation and amortization.

•	statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;

•	statements relating to future financial or operational performance, future dividends, future capital sources and capital expenditures; and

•	any other statements preceded by, followed by or that include the words "anticipates," "believes," "expects," "plans," "intends," "estimates," "projects," "could," "should," "may," or similar expressions.

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(1)	The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO).

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(1)	Amounts are shown exclusive of depreciation and amortization.

(2)

EBITDA and Adjusted EBITDA. EBITDA represents net income before (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, major scheduled turnaround expenses, gain (loss) on derivatives, net, current period settlements on derivative contracts, loss on extinguishment of

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(a)	Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts.

(b)	Legal, professional and integration expenses related to the December 2011 acquisition.

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(1)	Amounts are shown exclusive of depreciation and amortization.

(2)	Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.

(3)

Gross profit is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses and depreciation and amortization. Each of the components used in this calculation are taken directly from the petroleum business' financial results. In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.

(4)

Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating the refineries' performance as a general indication of the amount above the cost of product sold that it is able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from the petroleum business' financial results. Our calculation of refining margin may differ from similar calculations of other companies in the industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate the petroleum business' ongoing operating results and allow for greater transparency in the review of our overall business, financial, operational and economic performance.

(5)

Adjusted Petroleum EBITDA represents operating income for the petroleum segment adjusted for (i) FIFO impacts (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) major scheduled turnaround expenses, (iv) current period settlements on derivatives contracts, (v) depreciation and amortization and (vi) and other income (expense), net. We present Adjusted Petroleum EBITDA because it is the starting point for the Refining Partnership's available cash for distribution. Adjusted Petroleum EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that Adjusted Petroleum EBITDA enables investors to better understand the Refining Partnership's ability to make distributions to its common

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(a)

FIFO is the petroleum business' basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period.

(b)	Represents expense associated with a major scheduled turnaround activities performed at the Coffeyville refinery ($5.5 million in 2014 and $21.2 million in 2012) and the Wynnewood refinery ($1.3 million in 2014 and $102.5 million in 2012).

(c)	Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at the inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts.

(6)	Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric.

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(1)	Barrels in millions

(2)	Sales dollars in millions

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(2)	Sales dollars in millions

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(1)	Amounts are shown exclusive of depreciation and amortization.

(2)

Adjusted Nitrogen Fertilizer EBITDA represents operating income adjusted for (i) share-based compensation, non-cash, (ii) major scheduled turnaround expenses, (iii) depreciation and amortization and (iv) other income (expense). The Nitrogen Fertilizer Partnership recorded share-based compensation, non-cash, in each of the periods presented below and its plant generally undergoes a major scheduled turnaround every two to three years. We present Adjusted Nitrogen Fertilizer EBITDA because we have found it helpful to consider an operating measure that excludes expenses, such as major scheduled turnaround expense, relating to transactions not reflective of the Nitrogen Fertilizer Partnership's core operations. In addition, we believe that it is useful to exclude from Adjusted Nitrogen Fertilizer EBITDA share-based compensation, non-cash, although it is a recurring cost incurred in the ordinary course of business. We believe share-based compensation, non-cash, reflects a non-cash cost which may obscure, for a given period, trends in the underlying business, due to the timing and nature of the equity awards. We also present Adjusted Nitrogen Fertilizer EBITDA because it is the starting point for the Nitrogen Fertilizer Partnership's available cash for distribution.

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(a)	Represents expense associated with a major scheduled turnaround at the nitrogen fertilizer plant.

(3)

Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. As a result of the completion of the UAN expansion project in February 2013, the Nitrogen Fertilizer Partnership now upgrades substantially all of the ammonia it produces into UAN. Net tons available for sale represent the ammonia available for sale that was not upgraded into UAN.

(4)	In addition to produced ammonia, the Nitrogen Fertilizer Partnership acquired approximately 33,600 and 17,300 tons of ammonia during the years ended December 31, 2014 and 2013, respectively. The Partnership has upgraded or expects to upgrade the majority of purchased ammonia to UAN. The Nitrogen Fertilizer Partnership did not purchase ammonia during the year ended December 31, 2012.

(5)	Product pricing at gate per ton represents net sales less freight revenue divided by product sales volume in tons and is shown in order to provide a pricing measure that is comparable across the fertilizer industry.

(6)	On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period and is a measure of operating efficiency.

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(1)	UAN and ammonia sales volumes are in tons. Hydrogen sales volumes are in MSCF.

(2)	Includes freight charges. Hydrogen is based on $ per MSCF.

(3)	Sales dollars in millions.

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(1)	Ammonia and UAN sales volumes are in tons. Hydrogen sales volumes are in MSCF.

(2)	Includes freight charges. Hydrogen is based on $ per MSCF.

(3)	Sales dollars in millions.

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(1)	Consists of the 2022 Notes and the Nitrogen Fertilizer Partnership's term loan facility outstanding as of December 31, 2014.

(2)	The Refining Partnership and the Nitrogen Fertilizer Partnership lease various facilities and equipment, including railcars and real property, under operating leases for various periods.

(3)	The amount includes commitments under capital lease arrangements for equipment and for two leases associated with pipelines and storage and terminal equipment at the Wynnewood refinery.

(4)

The amount includes (a) commitments under several agreements for the petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an electric supply agreement with the city of Coffeyville, (c) a product supply agreement with Linde, (d) a pet coke supply agreement with HollyFrontier Corporation with a term ending in December 2015, subject to renewal, (e) commitments related to our

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(5)

Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas. We also are required to make payments with respect to other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See "Business — Environmental Matters."

(6)	Interest payments are based on stated interest rates for our long-term debt outstanding and interest payments for the capital lease obligations as of December 31, 2014.

(7)	Standby letters of credit issued against our Amended and Restated ABL Credit Facility include $0.2 million of letters of credit issued in connection with environmental liabilities, $26.3 million in letters of credit to secure transportation services for crude oil and a $0.8 million letter of credit issued to guarantee a portion of our insurance policy.

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•	general economic conditions;

•	fertilizer pricing;

•	input costs; and

•	customer outlook.

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•	lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows;

•	hedge the value of inventories in excess of minimum required inventories; and

•	manage existing derivative positions related to a change in anticipated operations and market conditions.

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Time Basis — In entering over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underlying physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods, then weighted-average physical prices will be weighted differently than the swap price as the result of timing.

•	Location Basis — In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area.

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•	common units representing limited partner interests; and

•	a general partner interest, which is not entitled to any distributions, and which is held by the Nitrogen Fertilizer Partnership's general partner.

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•	common units representing limited partner interests; and

•	a general partner interest, which is not entitled to any distributions, and which is held by the Refining Partnership's general partner.

•	approximately $253.0 million was used to repurchase the 10.875% senior secured notes due 2017 (including accrued interest);

•	approximately $160.0 million was used to fund certain maintenance and environmental capital expenditures through 2014;

•	approximately $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery that were incurred during the fourth quarter of 2012;

•	approximately $85.1 million was distributed to CRLLC; and

•	the balance of the proceeds of approximately $101.5 million was allocated to be utilized by the Refining Partnership for general partnership purposes.

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(1)

This amount includes approximately $799.6 million payable ratably over sixteen years pursuant to petroleum transportation service agreements between CRRM and each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (together "TransCanada"). The purchase obligation reflects the exchange rate between the Canadian dollar and the U.S. dollar as of December 31, 2014, where applicable. Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada's Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011.

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•	Level 1 — Quoted prices in active markets for identical assets and liabilities

•	Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)

•	Level 3 — Significant unobservable inputs (including the Company's own assumptions in determining the fair value)

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