UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-Q

 

 

Commission file number: 001-33492

 

CVR ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code:

(281) 207-3200

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 or Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o

 

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).  Yes o     No þ

 

There were 86,250,079 shares of the registrant’s common stock outstanding at November 2, 2009.

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended September 30, 2009

 

GLOSSARY OF SELECTED TERMS

 

The following are definitions of certain industry terms used in this Form 10-Q.

 

2-1-1 crack spread — The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of heating oil. The 2-1-1 crack spread is expressed in dollars per barrel.

 

Ammonia — Ammonia is a direct application fertilizer and is primarily used as a building block for other nitrogen products for industrial applications and finished fertilizer products.

 

Backwardation markets — Market situation in which futures prices are lower in succeeding delivery months. Also known as an inverted market. The opposite of contango.

 

Barrel — Common unit of measure in the oil industry which equates to 42 gallons.

 

Blendstocks — Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.

 

bpd — Abbreviation for barrels per day.

 

Bulk sales — Volume sales through third party pipelines, in contrast to tanker truck quantity sales.

 

Capacity — Capacity is defined as the throughput a process unit is capable of sustaining, either on a calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as feedstock costs, product values and downstream unit constraints.

 

Catalyst — A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.

 

Common units — The class of interests issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which provide for voting rights and have rights with respect to profits and losses of, and distributions from, the respective limited liability companies.

 

Contango markets — Markets that are characterized by prices for future delivery that are higher than the current or spot price of the commodity.

 

Crack spread — A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of diesel fuel.

 

Distillates — Primarily diesel fuel, kerosene and jet fuel.

 

Farm belt — Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin.

 

Feedstocks — Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products.

 

Heavy crude oil — A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel.

 

Independent petroleum refiner — A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock in its refinery operations from third parties.

Light crude oil — A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.

 

Magellan — Magellan Midstream Partners L.P., a publicly traded company whose business is the transportation, storage and distribution of refined petroleum products.

 

MMBtu — One million British thermal units:  a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.

 

Natural gas liquids — Natural gas liquids, often referred to as NGLs, are feedstocks used in the manufacture of refined fuels. Common NGLs used include propane, isobutane, normal butane and natural gasoline.

 

PADD II — Midwest Petroleum Area for Defense District, which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee and Wisconsin.

 

Petroleum coke (Pet coke) — A coal-like substance that is produced during the refining process.

 

Refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.

 

Sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.

 

Sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.

 

Throughput — The volume processed through a unit or a refinery.

 

Turnaround — A periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to four years.

 

UAN — UAN is a solution of urea and ammonium nitrate in water used as a fertilizer.

 

WTI — West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

 

WTS — West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of 30-32 degrees and a sulfur content of approximately 2.0 weight percent.

 

Yield — The percentage of refined products that is produced from crude and other feedstocks.

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

See accompanying notes to the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

See accompanying notes to the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

See accompanying notes to the condensed consolidated financial statements.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(unaudited)

 

 

Organization

 

The “Company” or “CVR” may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries. Any references to the “Company” as of a date prior to October 16, 2007 (the date of the restructuring as further discussed in this Note) and subsequent to June 24, 2005 are to Coffeyville Acquisition LLC (“CALLC”) and its subsidiaries.

 

The Company, through its wholly-owned subsidiaries, acts as an independent petroleum refiner and marketer in the mid-continental United States. In addition, the Company, through its majority-owned subsidiaries, acts as an independent producer and marketer of upgraded nitrogen fertilizer products in North America. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.

 

CALLC formed CVR Energy, Inc. as a wholly-owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering. The initial public offering of CVR was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”).

 

CVR is a controlled company under the rules and regulations of the New York Stock Exchange where its shares are traded under the symbol “CVI.” As of September 30, 2009, approximately 73% of its outstanding shares were beneficially owned by GS Capital Partners V, L.P. and related entities (“GS” or “Goldman Sachs Funds”) and Kelso Investment Associates VII, L.P. and related entities (“Kelso” or “Kelso Funds”).

 

Nitrogen Fertilizer Limited Partnership

 

In conjunction with the consummation of CVR’s initial public offering in 2007, CVR transferred Coffeyville Resources Nitrogen Fertilizer, LLC (“CRNF”), its nitrogen fertilizer business, to a newly created limited partnership, CVR Partners, LP (the “Partnership”), in exchange for a managing general partner interest (“managing GP interest”), a special general partner interest (“special GP interest,” represented by special GP units) and a de minimis limited partner interest (“LP interest,” represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest to Coffeyville Acquisition III LLC (“CALLC III”), an entity owned by its controlling stockholders and senior management, at fair market value. The board of directors of CVR determined, after consultation with management, that the fair market value of the managing GP interest was $10,600,000. This interest has been classified as a noncontrolling interest included as a separate component of equity in the Consolidated Balance Sheets at September 30, 2009 and December 31, 2008.

 

CVR owns all of the interests in the Partnership (other than the managing GP interest and the associated incentive distribution rights (“IDRs”)) and is entitled to all cash distributed by the Partnership except with respect to IDRs. The managing general partner is not entitled to participate in Partnership distributions except with respect to its IDRs, which entitle the managing general partner to receive increasing percentages (up to 48%) of the cash the Partnership distributes in excess of $0.4313 per unit in a quarter. However, the Partnership is not permitted to make any distributions with respect to the IDRs until the aggregate Adjusted Operating Surplus, as defined in the Partnership’s partnership agreement, generated by the Partnership through December 31, 2009, has been distributed in respect of the units held by CVR and any common units issued by the Partnership if it elects to pursue an initial public offering. In addition, the Partnership and its subsidiaries

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

are currently guarantors under the credit facility of Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR. There will be no distributions paid with respect to the IDRs for so long as the Partnership or its subsidiaries are guarantors under the credit facility.

 

The Partnership is operated by CVR’s senior management pursuant to a services agreement among CVR, the managing general partner, and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, CVR, as special general partner. As special general partner of the Partnership, CVR has joint management rights regarding the appointment, termination, and compensation of the chief executive officer and chief financial officer of the managing general partner, has the right to designate two members of the board of directors of the managing general partner, and has joint management rights regarding specified major business decisions relating to the Partnership. CVR, the Partnership, and the managing general partner also entered into a number of agreements to regulate certain business relations between the parties.

 

At September 30, 2009, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interests outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the managing general partner owned the managing GP interest and the IDRs. The managing general partner contributed 1% of CRNF’s interest to the Partnership in exchange for its managing GP interest and the IDRs.

 

In accordance with the Contribution, Conveyance, and Assumption Agreement, by and between the Partnership and the partners, dated as of October 24, 2007, if an initial private or public offering of the Partnership is not consummated by October 24, 2009, the managing general partner of the Partnership can require the Company to purchase the managing GP interest. This put right expires on the earlier of (1) October 24, 2012 or (2) the closing of the Partnership’s initial private or public offering. If the Partnership’s initial private or public offering is not consummated by October 24, 2012, the Company has the right to require the managing general partner to sell the managing GP interest to the Company. This call right expires on the closing of the Partnership’s initial private or public offering. In the event of an exercise of a put right or a call right, the purchase price will be the fair market value of the managing GP interest at the time of the purchase determined by an independent investment banking firm selected by the Company and the managing general partner.

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of CVR and its majority-owned direct and indirect subsidiaries. The ownership interests of noncontrolling investors in its subsidiaries are classified as a noncontrolling interest included as a separate component of equity for all periods presented. All intercompany account balances and transactions have been eliminated in consolidation. Certain information and footnotes required for complete financial statements under GAAP have been condensed or omitted pursuant to SEC rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 2008 audited consolidated financial statements and notes thereto included in CVR’s Annual Report on Form 10-K for the year ended December 31, 2008, which was filed with the SEC on March 13, 2009.

 

In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Company as of September 30, 2009 and December 31, 2008, the results of operations for the three months and nine months ended September 30, 2009 and 2008, and the cash flows for the nine months ended September 30, 2009 and 2008.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending December 31, 2009 or any other interim period. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

 

As a result of the adoption of Accounting Standards Codification (“ASC”) subsections regarding Noncontrolling Interests, on January 1, 2009, the noncontrolling interest for the year ended December 31, 2008 has been properly reclassified to be included in the Company’s equity section of the Consolidated Balance Sheets.

 

The Company evaluated subsequent events, if any, that would require an adjustment to the Company’s financial statements or require disclosure in the notes to the financial statements. The Company has evaluated subsequent events through November 4, 2009, the date of issuance of the condensed consolidated financial statements. (See Note 16 (“Subsequent Events”) for discussion.)

 

 

In June 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162 (the “Codification”). The Codification reorganized existing U.S. accounting and reporting standards issued by the FASB and other related private sector standard setters into a single source of authoritative accounting principles arranged by topic. The Codification supersedes all existing U.S. accounting standards; all other accounting literature not included in the Codification (other than SEC guidance for publicly-traded companies) is considered non-authoritative. The Codification was effective on a prospective basis for interim and annual reporting periods ending after September 15, 2009. As required, the Company adopted this standard as of July 1, 2009. The adoption of the Codification changed the Company’s references to U.S. GAAP accounting standards but did not impact the Company’s financial position or results of operations.

 

In June 2009, the FASB issued an amendment to a previously issued standard regarding consolidation of variable interest entities. This amendment is intended to improve financial reporting by enterprises involved with variable interest entities. The provisions of the amendment are effective as of the beginning of the entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. The Company is currently evaluating the impact of the standard, but does not believe it will have a material impact on the Company’s financial position or results of operations.

 

In May 2009, the FASB issued general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or available to be issued. This standard became effective June 15, 2009 and is to be applied to all interim and annual financial periods ending thereafter. It requires the disclosure of the date through which the Company has evaluated subsequent events and the basis for that date — that is, whether that date represents the date the financial statements were issued or were available to be issued. As required, the Company adopted this standard as of April 1, 2009. As a result of this adoption, the Company provided additional disclosures regarding the evaluation of subsequent events and the date through which that evaluation took place. There is no impact on the financial position or results of operations of the Company as a result of this adoption.

 

In April 2009, the FASB issued guidance for determining the fair value of an asset or liability when there has been a significant decrease in market activity. In addition, this standard requires additional disclosures regarding the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during annual or interim periods. As required, the Company

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

adopted this standard as of April 1, 2009. Based upon the Company’s assets and liabilities currently subject to the provisions of this standard, there is no impact on the Company’s financial position, results of operations or disclosures as a result of this adoption.

 

In June 2008, the FASB issued guidance to assist companies when determining whether instruments granted in share-based payment transactions are participating securities, which became effective January 1, 2009 and is to be applied retrospectively. Under this guidance, unvested share-based payment awards, which receive non-forfeitable dividend rights or dividend equivalents, are considered participating securities and are now required to be included in computing earnings per share under the two class method. As required, the Company adopted this standard as of January 1, 2009. Based upon the nature of the Company’s share-based payment awards, it has been determined that these awards are not participating securities and, therefore, the standard currently has no impact on the Company’s earnings per share calculations.

 

In March 2008, the FASB issued an amendment to the previously issued standard regarding the accounting for derivative instruments and hedging activities. This amendment changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedge items affect an entity’s financial position, net earnings, and cash flows. As required, the Company adopted this amendment as of January 1, 2009. As a result of the adoption, the Company provided additional disclosures regarding its derivative instruments in the notes to the condensed consolidated financial statements. There is no impact on the financial position or results of operations of the Company as a result of this adoption.

 

In February 2008, the FASB issued guidance which defers the effective date of a previously issued standard regarding the accounting for and disclosure of fair value measurements of nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually). As required, the Company adopted this guidance as of January 1, 2009. This adoption did not impact the Company’s financial position or results of operations.

 

In December 2007, the FASB issued an amendment to a previously issued standard that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This amendment requires retroactive adoption of the presentation and disclosure requirements for existing noncontrolling interests. All other requirements of this amendment must be applied prospectively. The Company adopted this amendment effective January 1, 2009, and as a result has classified the noncontrolling interest (previously minority interest) as a separate component of equity for all periods presented.

 

 

Prior to CVR’s initial public offering in October 2007, CVR’s subsidiaries were held and operated by CALLC, a limited liability company. Management of CVR holds an equity interest in CALLC. CALLC issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with CVR’s initial public offering, CALLC was split into two entities: CALLC and CALLC II. In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting override units, was split so that half of management’s equity interest was in CALLC and half was in CALLC II. CALLC was historically the primary reporting company and CVR’s predecessor. In addition, in connection with the transfer of the managing GP interest of the Partnership to CALLC III in October 2007, CALLC III issued non-voting override units to certain management members of CALLC III.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

CVR, CALLC, CALLC II and CALLC III account for share-based compensation in accordance with FASB ASC 718, Share-Based Payments, and FASB ASC 323, Accounting by an Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee. CVR has been allocated non-cash share-based compensation expense from CALLC, CALLC II and CALLC III.

 

In accordance with FASB ASC 718, CVR, CALLC, CALLC II and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. In accordance with FASB ASC 323, CVR recognizes the costs of the share-based compensation incurred by CALLC, CALLC II and CALLC III on its behalf, primarily in selling, general, and administrative expenses (exclusive of depreciation and amortization), and a corresponding capital contribution, as the costs are incurred on its behalf, following the guidance in FASB ASC 505, Accounting for Equity Investments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling Goods or Services, which requires remeasurement at each reporting period through the performance commitment period, or in CVR’s case, through the vesting period.

 

At September 30, 2009, the value of the override units of CALLC and CALLC II was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of the Company’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are vested.

 

The estimated fair value of the override units of CALLC III has been determined using a probability-weighted expected return method which utilizes CALLC III’s cash flow projections, which are representative of the nature of interests held by CALLC III in the Partnership.

 

The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC III. Compensation expense amounts are disclosed in thousands.

 

 

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

Valuation Assumptions

 

Significant assumptions used in the valuation of the Override Operating Units (a) and (b) were as follows:

 

 

On the tenth anniversary of the issuance of override operating units, such units convert into an equivalent number of override value units. Override operating units are forfeited upon termination of employment for cause. The explicit service period for override operating unit recipients is based on the forfeiture schedule below. In the event of all other terminations of employment, the override operating units are initially subject to forfeiture as follows:

 

 

Significant assumptions used in the valuation of the Override Value Units (c) and (d) were as follows:

 

 

Unless the compensation committee of the board of directors of CVR takes an action to prevent forfeiture, override value units are forfeited upon termination of employment for any reason, except that in the event of termination of employment by reason of death or disability, all override value units are initially subject to forfeiture as follows:

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

 

 

At September 30, 2009, assuming no change in the estimated fair value at September 30, 2009, there was approximately $10,381,000 of unrecognized compensation expense related to non-voting override units. This expense is expected to be recognized over a remaining period of approximately three years as follows (in thousands):

 

 

Phantom Unit Plans

 

CVR, through a wholly-owned subsidiary, has two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points have rights to receive

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

distributions when holders of override operating units receive distributions. Holders of performance phantom points have rights to receive distributions when holders of override value units receive distributions. There are no other rights or guarantees and the plan expires on July 25, 2015, or at the discretion of the compensation committee of the board of directors. As of September 30, 2009, the issued Profits Interest (combined phantom points and override units) represented 15.0% of combined common unit interest and Profits Interest of CALLC and CALLC II. The Profits Interest was comprised of approximately 11.1% of override interest and approximately 3.9% of phantom interest. In accordance with FASB ASC 505, the expense associated with these awards for 2009 is based on the current fair value of the awards which was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of the Company’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled. Based upon this methodology, the service phantom interest and performance phantom interest were valued at $23.44 and $18.28 per point, respectively, at September 30, 2009. In accordance with FASB ASC 505, using the September 30, 2008 CVR stock closing price to determine the Company’s equity value, through an independent valuation process, the service phantom interest and performance phantom interest were valued at $17.54 and $7.06 per point, respectively. CVR has recorded approximately $16,547,000 and $3,882,000 in personnel accruals as of September 30, 2009 and December 31, 2008, respectively. Compensation expense for the three and nine months ended September 30, 2009 related to the Phantom Unit Plans was $8,166,000 and $12,665,000, respectively. Compensation expense related to the Phantom Unit Plan for the three and nine months ended September 30, 2008 was reversed by $(17,977,000) and $(21,233,000), respectively.

 

At September 30, 2009, assuming no change in the estimated fair value at September 30, 2009, there was approximately $3,486,000 of unrecognized compensation expense related to the Phantom Unit Plans. This is expected to be recognized over a remaining period of approximately two years.

 

Long Term Incentive Plan

 

CVR has a Long Term Incentive Plan (“LTIP”) which permits the grant of options, stock appreciation rights, or SARS, non-vested shares, non-vested share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance based restricted stock).

 

Stock Options

 

As of September 30, 2009, there have been a total of 32,350 stock options granted, of which 10,786 have vested as of September 30, 2009. As of December 31, 2008, 6,302 options were vested and an additional 3,034 vested in the third quarter of 2009, respectively. There were no additional grants or forfeitures of stock options for the nine months ended September 30, 2009. As of September 30, 2009, there was approximately $77,000 of total unrecognized compensation cost related to stock options to be recognized over a weighted-average period of approximately one and one-half years.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Non-Vested Stock

 

A summary of non-vested stock grant activity and changes during the nine months ended September 30, 2009 is presented below:

 

 

Through the LTIP, shares of non-vested stock have been granted to employees and directors of the Company. These shares generally vest over a three-year period. As of September 30, 2009, there was approximately $329,000 of total unrecognized compensation cost related to non-vested shares to be recognized over a weighted-average period of approximately two years.

 

Compensation expense recorded for the three months ended September 30, 2009 and 2008 related to the non-vested stock and stock options was $125,000 and $102,000, respectively. Compensation expense recorded for the nine months ended September 30, 2009 and 2008 related to non-vested stock and stock options was $340,000 and $288,000, respectively.

 

 

Inventories consist primarily of crude oil, blending stock and components, work in progress, fertilizer products, and refined fuels and by-products. Inventories are valued at the lower of the first-in, first-out (“FIFO”) cost or market for fertilizer products, refined fuels and by-products for all periods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bear process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

 

Inventories consisted of the following (in thousands):

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

A summary of costs for property, plant, and equipment is as follows (in thousands):

 

 

Capitalized interest recognized as a reduction in interest expense for the three months ended September 30, 2009 and September 30, 2008 totaled approximately $536,000 and $244,000, respectively. Capitalized interest for the nine months ended September 30, 2009 and 2008 totaled approximately $1,338,000 and $1,565,000, respectively. Land and buildings that are under a capital lease obligation approximated $4,827,000 as of September 30, 2009. Amortization of assets held under capital leases is included in depreciation expense.

 

 

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, pet coke expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of $727,000 and $605,000 for the three months ended September 30, 2009 and 2008, respectively. For the nine months ended September 30, 2009 and 2008, cost of product sold excludes depreciation and amortization of $2,157,000 and $1,816,000, respectively.

 

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses excludes depreciation and amortization of $20,312,000 and $19,486,000 for the three months ended September 30, 2009 and 2008, respectively. For the nine months ended September 30, 2009 and 2008, direct operating expenses exclude depreciation and amortization of $59,975,000 and $58,296,000, respectively.

 

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate office in Texas and the administrative office in Kansas. Selling, general and administrative expenses excludes depreciation and amortization of $595,000 and $518,000 for the three months ended September 30, 2009 and 2008, respectively. For the nine months ended September 30, 2009 and 2008, selling, general and administrative expenses exclude depreciation and amortization of $1,518,000 and $1,212,000, respectively.

 

 

The Company entered into an insurance premium finance agreement in July 2009 to finance a portion of the purchase of its 2009/2010 property, liability, cargo and terrorism policies. The original balance of the note provided by the Company under such agreement was $10,000,000. As of September 30, 2009, the Company owed $10,000,000 related to this note. This note shall be repaid in equal installments commencing November 1,

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

2009, with the final payment due in June 2010. As of December 31, 2008, the Company owed $7,500,000 in connection with the 2008/2009 premium financing agreement originally entered into in July 2008. This note was paid in full in June 2009.

 

The Company also entered into a capital lease for real property used for corporate purposes on May 29, 2008. The lease had an initial lease term of one year with an option to renew for three additional one-year periods. During the second quarter of 2009, the Company renewed the lease for a one-year period commencing June 5, 2009. Quarterly lease payments made in connection with this capital lease total $80,000 annually. The Company also has the option to purchase the property during the term of the lease, including the renewal periods. In connection with the capital lease, the Company originally recorded a capital asset and capital lease obligation of $4,827,000. The capital lease obligation was $4,200,000 and $4,043,000 as of September 30, 2009 and December 31, 2008, respectively.

 

 

For the three months ended September 30, 2009 and 2008, the Company recorded pre-tax expenses, net of anticipated insurance recoveries of $529,000 and $(817,000), respectively, associated with the June/July 2007 flood and associated crude oil discharge. For the nine months ended September 30, 2009 and 2008, the Company recorded pre-tax expenses, net of anticipated insurance recoveries of $609,000 and $8,842,000, respectively, associated with the June/July 2007 flood and associated crude oil discharge. The costs are reported in net costs associated with flood in the Consolidated Statements of Operations. Total accounts receivable from insurance was $1,000,000 at September 30, 2009 and $12,756,000 as of December 31, 2008. With the final insurance proceeds received under the Company’s property insurance policy and builders’ risk policy during the first quarter of 2009, in the amount of $11,756,000, all property insurance claims and builders’ risk claims were fully settled with all remaining claims closed. The receivable balance at September 30, 2009 is associated with the crude oil discharge. See Note 11 (“Commitments and Contingent Liabilities”) for additional information regarding environmental and other contingencies related to the crude oil discharge that occurred on July 1, 2007.

 

As of September 30, 2009, the remaining receivable from insurers was not anticipated to be collected in the next twelve months, and therefore has been classified as a non-current asset. Management believes the recovery of the receivable from the insurance carriers is probable.

 

 

As of September 30, 2009, the Company did not have any unrecognized tax benefits and did not have an accrual for any amounts for interest or penalties related to uncertain tax positions. The Company’s accounting policy with respect to interest and penalties related to tax uncertainties is to classify these amounts as income taxes.

 

CVR and its subsidiaries file U.S. federal and various state income and franchise tax returns. The Company’s U.S. federal and state tax years subject to examination as of September 30, 2009 are 2005 to 2008.

 

The Company’s effective tax rate for the three and nine months ended September 30, 2009 were 25.5% and 35.5%, respectively, as compared to the Company’s combined federal and state expected statutory tax rate of 39.7%. For the same periods in 2008, the effective tax rates were 28.9% and 25.1%, respectively. The effective tax rate is lower than the expected statutory tax rate for the three and nine months ended September 30, 2009 and 2008, respectively, due primarily to federal income tax credits available to small business refiners related to the production of ultra low sulfur diesel fuel. Additionally, the effective tax rate for 2008 was favorably impacted by Kansas state income tax incentives generated under the High Performance Incentive Program.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

Basic and diluted earnings per share are computed by dividing net income by weighted average common shares outstanding. The components of the basic and diluted earnings per share calculation are as follows:

 

 

Outstanding stock options totaling 32,350 common shares were excluded from the diluted earnings (loss) per share calculation for the three and nine months ended September 30, 2009 and 2008, respectively, as they were antidilutive. For the three months ended September 30, 2009, 100,066 shares of non-vested common stock were excluded from the diluted earnings (loss) per share calculation, as they were antidilutive.

 

 

Leases and Unconditional Purchase Obligations

 

The minimum required payments for the Company’s lease agreements and unconditional purchase obligations are as follows (in thousands):

 

 

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

The Company leases various equipment, including rail cars, and real properties under long-term operating leases, expiring at various dates. In the normal course of business, the Company also has long-term commitments to purchase services such as natural gas, electricity, water and transportation services. For the three months ended September 30, 2009 and 2008, lease expense totaled $1,316,000 and $1,102,000, respectively. For the nine months ended September 30, 2009 and 2008, lease expense totaled $3,798,000 and $3,176,000, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at the Company’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire. The Company also has other customary operating leases and unconditional purchase obligations primarily related to pipeline, utility and raw material suppliers. These leases and agreements are entered into in the normal course of business.

 

Litigation

 

Samson Resources Company, Samson Lone Star, LLC and Samson Contour Energy E&P, LLC (together, “Samson”) filed fifteen lawsuits in federal and state courts in Oklahoma and two lawsuits in state courts in New Mexico against Coffeyville Resources Refining & Marketing, LLC (“CRRM”) and other defendants between March 2009 and July 2009. All of the lawsuits allege that Samson sold crude oil to a now bankrupt group of companies, which generally are known as SemCrude or SemGroup (collectively, “Sem”), and that Sem has not paid Samson for all of the crude oil purchased from Sem. The lawsuits further allege that Sem sold some of the crude oil purchased from Samson to J. Aron & Company and that J. Aron & Company sold some of this crude oil to CRRM. All of the lawsuits seek the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. The amount of Samson’s alleged claims are unknown since the price and amount of crude oil sold by Samson and eventually received by CRRM through Sem and J. Aron, if any, is unknown. CRRM timely paid for all crude oil purchased from J. Aron & Company and intends to vigorously defend against these claims.

 

See the Note above for a discussion of the TransCanada litigation.

 

From time to time, the Company is involved in various lawsuits arising in the normal course of business, including matters such as those described below under “Environmental, Health, and Safety (“EHS”) Matters.” Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. Management believes the Company has accrued for losses for which it may ultimately be responsible. It is possible that management’s estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

 

Flood, Crude Oil Discharge and Insurance

 

Crude oil was discharged from the Company’s refinery on July 1, 2007 due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. In connection with that discharge, the Company received in May 2008 notices of claims from sixteen private claimants under the Oil Pollution Act in an aggregate amount of approximately $4,393,000. In August 2008, those claimants filed suit against the Company in the United States District Court for the District of Kansas in Wichita (“Angleton Case”). In October, 2009, a companion case to the Angleton Case was filed in the United States District Court for the District of Kansas at Wichita, seeking a total of $3,200,000 for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge. The Company believes that the resolution of these claims will not have a material adverse effect on the consolidated financial statements.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (the “Consent Order”) with the Environmental Protection Agency (“EPA”) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of oil from the Company’s refinery caused an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company’s refinery. The substantial majority of all known remedial actions were completed by January 31, 2009. The Company prepared its final report to the EPA to satisfy the final requirement of the Consent Order. The Company anticipates that the EPA’s review of this report will not result in any further requirements that could be material to the Company’s business, financial condition, or results of operations.

 

As of September 30, 2009, the total gross costs recorded associated with remediation and third party property damage as a result of the crude oil discharge approximated $54,938,000. The Company has not estimated or accrued for any potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from lawsuits related to the June/July 2007 flood as management does not believe any such fines, penalties or lawsuits would be material or can be estimated.

 

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and property damage claims. On July 10, 2008, the Company filed two lawsuits in the United States District Court for the District of Kansas against certain of the Company’s insurance carriers with regard to the Company’s insurance coverage for the June/July 2007 flood and crude oil discharge. The Company’s excess environmental liability insurance carrier has asserted that the Company’s pollution liability claims are for “cleanup,” which is not covered by such policy, rather than for “property damage,” which is covered to the limits of the policy. While the Company will vigorously contest the excess carrier’s position, it contends that if that position were upheld, the umbrella Comprehensive General Liability policies would continue to provide coverage for these claims. Each insurer, however, has reserved its rights under various policy exclusions and limitations and has cited potential coverage defenses. Although the Company believes that certain amounts under the environmental and liability insurance policies will be recovered, the Company cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims.

 

The lawsuit with the insurance carriers under the environmental liability and comprehensive general liability policies remains the only unsettled lawsuit with the insurance carriers. The property insurance lawsuit has been settled and dismissed.

 

Environmental, Health, and Safety (“EHS”) Matters

 

CRRM, Coffeyville Resources Crude Transportation, LLC (“CRCT”) and Coffeyville Resources Terminal, LLC (“CRT”), all of which are wholly-owned subsidiaries of CVR, and CRNF are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are 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 EHS liabilities, no offset is made for potential recoveries. Such liabilities include estimates of the Company’s share of costs attributable to potentially responsible parties which are insolvent or otherwise unable to pay. EHS liabilities are monitored and adjusted regularly as new facts emerge or changes in law or technology occur.

 

CRRM, CRNF, CRCT and CRT own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CRRM, CRNF, CRCT and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at some of these locations.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under the Resource Conservation and Recovery Act (“RCRA”) to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). In 2005, CRNF agreed to participate in the State of Kansas Voluntary Cleanup and Property Redevelopment Program (“VCPRP”) to address a reported release of UAN at its UAN loading rack. As of September 30, 2009 and December 31, 2008, environmental accruals of $5,495,000 and $6,924,000, respectively, were reflected in the consolidated balance sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders and the VCPRP, including amounts totaling $2,139,000 and $2,684,000, respectively, included in other current liabilities. The Company’s accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at September 30, 2009 and December 31, 2008, respectively. The accruals include estimated closure and post-closure costs of $1,326,000 and $1,124,000 for two landfills at September 30, 2009 and December 31, 2008, respectively. The estimated future payments for these required obligations are as follows (in thousands):

 

 

Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.

 

In February 2000, the EPA promulgated the Tier II Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline that were required to be met by 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. In February 2004, the EPA granted the Company approval under a “hardship waiver” that would defer meeting final Ultra Low Sulfur Gasoline (“ULSG”) standards and Ultra Low Sulfur Diesel (“ULSD”) requirements. The hardship waiver was revised at CRRM’s request on September 25, 2008. The Company met the conditions of the “hardship waiver” related to the ULSD requirements in late 2006 and is continuing its work related to meeting its compliance date with ULSG standards in accordance with a revised hardship waiver which gave the Company short-term flexibility on sulfur content during the recovery from the flood. Compliance with the Tier II gasoline and on-road diesel standards required us to spend approximately $13,787,000 during 2008, approximately $16,800,000 during 2007 and $79,033,000 during 2006. Based on information currently available, CRRM and CRT anticipate spending approximately $24,485,000 in 2009 and $16,242,000 in 2010 to comply with ULSG requirements. The entire amounts are expected to be capitalized. For the three months ended September 30, 2009 and 2008, CVR has spent $6,351,000 and $1,953,000, respectively. For the nine months ended September 30, 2009 and 2008, CVR has spent $13,433,000 and $10,120,000, respectively.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The EPA promulgated regulations in 2007 that require the reduction of benzene in gasoline by 2011. CRRM is a small refiner under this rule and compliance with the rule is extended until 2015 for small refiners. Because of the extended compliance date, CRRM has not begun engineering work at this time. CVR anticipates that capital expenditures to comply with the rule will not begin before 2013. Additionally, the EPA has proposed changes to the Renewable Fuel Standards (RFS) that, when finalized, may impact petroleum product demand in the future. Due to mandates in the rule requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, CVR may be impacted by increased costs to accommodate mandated renewable fuel volumes. CRRM is a small refiner under the current RFS rules and would be subject to any extended compliance dates under the rule when finalized.

 

In March 2004, CRRM entered into a Consent Decree (the “Consent Decree”) with the EPA and the Kansas Department of Health and Environment (“KDHE”), pursuant to which CRRM agreed, among other things, to install controls to reduce emissions of sulfur dioxide (SO₂), nitrogen oxides (NO_X), and particulate matter (PM) from its fluid catalytic cracking unit (FCCU) by January 1, 2011. See Item 1 “Business — Environmental Matters — The Federal Clean Air Act — Air Emissions” and Item 1A “Risk Factors — Risks Related to Our Entire Business — Environmental laws and regulation could require CRRM to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities” in our Form 10-K for the year ended December 31, 2008 for additional information related to the Consent Decree. To date, CRRM has materially complied with the Consent Decree. On June 30, 2009, CRRM submitted a force majeure notice to the EPA and KDHE in which CRRM indicated that it believes it may be unable to meet the Consent Decree deadlines related to the installation of controls on the FCCU because of delays caused by the June/July 2007 flood. The force majeure notice requests a one-year extension of the January 1, 2011 deadline. On September 17, 2009, the EPA rejected CRRM’s force majeure claim but also indicated that it would be willing to negotiate an extension of the deadline. On September 25, 2009, CRRM accepted the EPA’s offer to negotiate the matter, but invoked the dispute resolution provision of the Consent Decree in order to preserve CRRM’s ability to challenge EPA’s denial of CRRM’s force majeure claim. Negotiations with the EPA have commenced.

 

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended September 30, 2009 and 2008, capital environmental expenditures were $6,591,000 and $5,481,000, respectively. For the nine months ended September 30, 2009 and 2008, capital environmental expenditures totaled $15,958,000 and $34,842,000, respectively. These expenditures were incurred to improve the efficiency of the operations.

 

CRRM, CRNF, CRCT and CRT believe they are in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the Company’s business, financial condition, or results of operations.

 

 

In September 2006, the FASB issued FASB ASC 820. This statement established a single authoritative definition of fair value when accounting rules require the use of fair value, set out a framework for measuring fair value, and required additional disclosures about fair value measurements. FASB ASC 820 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

 

FASB ASC 820 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market conditions involving identical or comparable assets or liabilities), the income approach (techniques to convert future amounts to single present amounts based on market expectations including present value techniques and option-pricing), and the cost approach (amount that would be required to replace the service capacity of an asset which is often referred to as replacement cost). FASB ASC 820

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:

 

 

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of September 30, 2009 (in thousands):

 

 

As of September 30, 2009, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company’s money market account and derivative instruments. See Note 13 (“Derivative Financial Instruments”) for a discussion of the Cash Flow Swap and Interest Rate Swap. The Company’s derivative contracts giving rise to assets or liabilities under Level 2 are valued using pricing models based on other significant observable inputs. The carrying value of long-term and revolving debt, if any, approximates fair value as a result of floating interest rates assigned to those financial instruments.

 

 

Gain (loss) on derivatives, net consisted of the following (in thousands):

 

 

CVR is subject to price fluctuations caused by supply and demand conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, the Company may enter into various derivative transactions. The Company, as further described below, entered into certain commodity derivative contracts (i.e., the Cash Flow Swap) and an interest rate swap as required by the long-term debt agreements. The commodity derivative contracts are for the purpose of managing price risk on crude oil and finished goods and the interest rate swap is for the purpose of managing interest rate risk.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

CVR has adopted FASB ASC 815, Accounting for Derivative Instruments and Hedging Activities which imposes extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR holds derivative financial instruments, such as exchange-traded crude oil futures, certain over-the-counter forward swap agreements and interest rate swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges. Gains or losses related to the change in fair value and periodic settlements of these derivative financial instruments are classified as gain (loss) on derivatives, net in the Consolidated Statements of Operations.

 

Cash Flow Swap

 

At September 30, 2009, CVR’s Petroleum Segment held commodity derivative contracts (the “Cash Flow Swap”) for the period from July 1, 2005 to June 30, 2010 with a related party. See Note 14 (“Related Party Transactions”). The Cash Flow Swap agreements were originally executed on June 16, 2005 in conjunction with the acquisition by CALLC of all the outstanding stock held by Coffeyville Group Holdings, LLC and were required under the terms of the long-term debt agreements. The notional quantities on the date of execution were 100,911,000 barrels of crude oil, 2,348,802,750 gallons of unleaded gasoline and 1,889,459,250 gallons of heating oil. The Cash Flow Swap agreements were executed at the prevailing market rate at the time of execution. At September 30, 2009, the notional open amounts under the Cash Flow Swap agreements were 4,436,250 barrels of crude oil, 93,161,250 gallons of unleaded gasoline and 93,161,250 gallons of heating oil. These positions are marked to market at each reporting date and result in unrealized gains (losses) using a valuation method that utilizes quoted market prices and assumptions. All unrealized gains and losses are currently recognized in the Company’s Consolidated Statements of Operations. The realized gain or loss from the Cash Flow Swap is settled quarterly. All of the activity related to the commodity derivative contracts is reported in the Petroleum Segment. The Cash Flow Swap was terminated by the parties effective October 8, 2009. See below for further discussion.

 

As noted above, the counterparty to the Company’s Cash Flow Swap agreement is a related party. As prudent, the Company from time-to-time considers counterparty credit risk. The maximum amount of loss due to the credit risk of the counterparty, should the counterparty fail to perform according to the terms of the contracts, is contingent upon the unsettled portion of the Cash Flow Swap, if any. For the Company to be “at-risk” the unsettled portion of the Cash Flow Swap would need to be in a net receivable position. Based upon the quoted market prices as of September 30, 2009, the Company recorded a current receivable related to the Cash Flow Swap. As such, all or a portion of the receivable could be “at-risk” should the counterparty fail to perform. The Company originally provided a letter of credit totaling $150,000,000, issued in support of the Cash Flow Swap, which was reduced to $60,000,000 effective June 1, 2009. In connection with the termination of the Cash Flow Swap as discussed further below, the $60,000,000 funded letter of credit facility was terminated effective October 15, 2009.

 

On October 8, 2009, CRLLC and J. Aron mutually agreed to terminate the Cash Flow Swap. The Cash Flow Swap was expected to terminate in 2010; however, a recent amendment to the Company’s credit facility permitted early termination. As a result of the early termination, a settlement totaling approximately $3,851,000 was paid to CRLLC by the swap counterparty.

 

Interest Rate Swap

 

At September 30, 2009, CRLLC held derivative contracts known as Interest Rate Swap agreements (the “Interest Rate Swap”) that converted CRLLC’s floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of $180,000,000. Half of the Interest Rate Swap agreements are held with a related party (as described in Note 14, “Related Party Transactions”), and the other half are held with a financial institution that

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

is a lender under CRLLC’s long-term debt agreement. The Interest Rate Swap agreements carry the following terms:

 

 

CVR pays the fixed rates listed above and receives a floating rate based on three month LIBOR rates, with payments calculated on the notional amounts listed above. The notional amounts do not represent actual amounts exchanged by the parties but instead represent the amounts on which the contracts are based. The Interest Rate Swap results in both realized and unrealized gains or losses and is included in the Company’s Consolidated Statements of Operations. The realized gain or loss from the Interest Rate Swap is settled quarterly. The Interest Rate Swap is marked to market each reporting date. Transactions related to the Interest Rate Swap agreements are not allocated to the Petroleum or Nitrogen Fertilizer segments.

 

The Interest Rate Swap has two counterparties. As noted above, one half of the Interest Rate Swap agreements are held with a related party. As of September 30, 2009, both counterparties had an investment-grade debt rating. The maximum amount of loss due to the credit risk of the counterparty, should the counterparty fail to perform according to the terms of the contracts, is contingent upon the unsettled portion of the Interest Rate Swap, if any. For the Company to be “at-risk” the unsettled portion of the Interest Rate Swap would need to be in a net receivable position. As of September 30, 2009, the Company’s Interest Rate Swap was in a payable position and thus would not be considered “at-risk” as it relates to risk posed by the swap counterparties.

 

 

The Goldman Sachs Funds and the Kelso Funds together own a majority of the common stock of the Company.

 

Cash Flow Swap

 

CRLLC entered into certain crude oil, heating oil and gasoline swap agreements (referred to above and herein as the Cash Flow Swap) with J. Aron & Company (“J. Aron”), a subsidiary of GS. These agreements were entered into on June 16, 2005, with an expiration date of June 30, 2010 (as described in Note 13, “Derivative Financial Instruments”). Net realized and unrealized gains totaling $2,768,000 and $65,153,000 were recognized related to these swap agreements for the three months ended September 30, 2009 and 2008, respectively, and are reflected in gain (loss) on derivatives, net in the Consolidated Statements of Operations. For the nine months ended September 30, 2009 and 2008, the Company recognized net realized and unrealized losses of $55,638,000 and $38,696,000, respectively, related to the Cash Flow Swap. These losses are reflected in gain (loss) on derivatives, net in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheet at September 30, 2009, includes an asset of $3,680,000 included in current receivable from swap counterparty, which represents the unrealized position and realized unsettled quarterly gains associated with the Cash Flow Swap at that date. The Cash Flow Swap was terminated by the parties effective October 8, 2009. The termination resulted in a settlement payment received by the Company from J. Aron totaling approximately $3,851,000. As of December 31, 2008, the Company recorded short-term and long-term receivables from swap counterparty of $32,630,000 and $5,632,000, respectively.

 

J. Aron Deferrals

 

As a result of the June/July 2007 flood and the related temporary cessation of business operations, the Company entered into deferral agreements for amounts owed to J. Aron under the Cash Flow Swap discussed

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

above. The amount deferred, excluding accrued interest, totaled $123,681,000. Of the deferred balances, $61,306,000 had been repaid as of December 31, 2008. The remaining deferred liability is included in the Consolidated Balance Sheet at December 31, 2008 in payable to swap counterparty. Accrued interest related to the deferral agreement for the year ended December 31, 2008 totaled $202,000 and is included in other current liabilities. Interest expense related to the deferral agreement totaled $0 and $1,364,000 for the three months ended September 30, 2009 and 2008, respectively. Interest expense related to the deferral agreement totaled $307,000 and $3,949,000 for the nine months ended September 30, 2009 and 2008, respectively.

 

In the first quarter of 2009, the Company repaid the entire remaining deferral obligation of $62,375,000, including accrued interest of $509,000, resulting in the Company being released from any and all of its obligations under the deferral agreements.

 

Interest Rate Swap

 

On June 30, 2005, the Company also entered into three Interest Rate Swap agreements (referred to above as the Interest Rate Swap) with J. Aron (as described in Note 13, “Derivative Financial Instruments”). Losses totaling $299,000 and $256,000 were recognized related to these swap agreements for the three months ended September 30, 2009 and 2008, respectively, and are reflected in gain (loss) on derivatives, net in the Consolidated Statements of Operations. Losses totaling $706,000 and $1,107,000 were recognized related to these swap agreements for the nine months ended September 30, 2009 and 2008, respectively, and are reflected in gain (loss) on derivatives, net in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheet at September 30, 2009 and December 31, 2008 includes $2,240,000 and $2,595,000, respectively, in other current liabilities. In addition to the other current liability, the Company recorded $1,298,000 in other long-term liabilities related to the same agreements as of December 31, 2008.

 

Crude Oil Supply Agreement

 

During 2008, the Company was a counterparty to a crude oil supply agreement with J. Aron. Under the agreement, the parties agreed to negotiate the cost of each barrel of crude oil to be purchased from a third party, and CRRM agreed to pay J. Aron a fixed supply service fee per barrel over the negotiated cost of each barrel of crude purchased. The cost was adjusted further using a spread adjustment calculation based on the time period the crude oil was estimated to be delivered to the refinery, other market conditions, and other factors deemed appropriate. The Company recorded $0 and $8,211,000 on the Consolidated Balance Sheet at September 30, 2009 and December 31, 2008, respectively, in prepaid expenses and other current assets for the prepayment of crude oil. In addition, $0 and $20,063,000 were recorded in inventory and $0 and $2,757,000 were recorded in accounts payable at September 30, 2009 and December 31, 2008, respectively. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the three and nine months ended September 30, 2008 totaled $966,006,000 and $2,640,135,000, respectively. For the three and nine months ended September 30, 2009, there were no expenses included in cost of product sold (exclusive of depreciation and amortization) as the crude oil supply agreement was terminated with J. Aron effective December 31, 2008. The Company entered into a new crude oil supply agreement with Vitol Inc. (“Vitol”), an unrelated party, effective December 31, 2008. The original crude oil supply agreement with Vitol included an initial term of two years. On July 7, 2009, the Company entered into an amendment with Vitol extending the term by a period of one year, terminating on December 31, 2011.

 

Cash and Cash Equivalents

 

The Company opened a highly liquid money market account with average maturities of less than 90 days within the Goldman Sachs fund family in September 2008. As of September 30, 2009 and December 31, 2008, the balance in the account was approximately $60,217,000 and $149,000, respectively. For the three and

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

nine months ended September 30, 2009, the account earned interest income of $24,000 and $68,000, respectively. For the three and nine months ended September 30, 2008, this account earned interest income of approximately $5,000.

 

Other

 

For the nine months ended September 30, 2009, the Company purchased approximately $115,000 of Fluid Catalytic Cracking Unit additives from Intercat, Inc. A director of the Company, Mr. Regis Lippert, is also the Director, President, CEO and majority shareholder of Intercat, Inc.

 

Subsequent to September 30, 2009, CRLLC amended its credit facility. See Note 16 (“Subsequent Events”) for discussion. In October 2009, CRLLC paid a subsidiary of GS a fee of $900,000 in connection with their services as lead bookrunner related to the amendment. As of September 30, 2009, $350,000 of this fee was payable to the subsidiary of GS. Additionally, the Company paid a lender fee of approximately $7,000 in conjunction with this amendment to a different subsidiary of GS. The affiliate is one of the many lenders under the credit facility.

 

 

CVR measures segment profit as operating income for Petroleum and Nitrogen Fertilizer, CVR’s two reporting segments, based on the definitions provided in FASB ASC 280 , Disclosures about Segments of an Enterprise and Related Information. All operations of the segments are located within the United States.

 

Petroleum

 

Principal products of the Petroleum Segment are refined fuels and petroleum refining by-products including pet coke. CVR sells the pet coke to the Partnership for use in the manufacturing of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. CVR uses a per-ton transfer price to record intercompany sales on the part of the Petroleum Segment and corresponding intercompany cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. The per ton transfer price paid, pursuant to the pet coke supply agreement that became effective October 24, 2007, is based on the lesser of a pet coke price derived from the price received by the fertilizer segment for UAN (subject to a UAN based price ceiling and floor) and a pet coke price index for pet coke. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in petroleum net sales were $636,000 and $3,353,000 for the three months ended September 30, 2009 and 2008, respectively. Intercompany sales included in petroleum net sales were $5,656,000 and $8,959,000 for the nine months ended September 30, 2009 and 2008, respectively.

 

The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under “Nitrogen Fertilizer” for the three and nine months ended September 30, 2009 of $(572,000) and $(357,000), respectively. For the three and nine months ended September 30, 2008, the Petroleum Segment purchased hydrogen from the Partnership and recorded cost of product sold (exclusive of depreciation and amortization) of $40,000 and $7,932,000, respectively.

 

Nitrogen Fertilizer

 

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was $1,360,000 and $3,364,000 for the three months ended September 30, 2009 and 2008, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was $7,444,000 and $8,235,000 for the nine months ended September 30, 2009 and 2008, respectively.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Pursuant to the feedstock agreement, the Company’s segments have the right to transfer excess hydrogen to one another. Sales of hydrogen to the Petroleum Segment have been reflected as net sales for the Nitrogen Fertilizer Segment. Receipts of hydrogen from the Petroleum Segment have been reflected in cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. The Nitrogen Fertilizer Segment recorded net sales from intercompany hydrogen sales of $0 and $659,000 for the three and nine months ended September 30, 2009, respectively and recorded cost of product sold (exclusive of depreciation and amortization) of $572,000 and $1,016,000 for the three and nine months ended September 30, 2009, respectively, for the purchase of intercompany hydrogen. For the three and nine months ended September 30, 2008 the Nitrogen Fertilizer Segment recorded net sales of hydrogen to the Petroleum Segment totaling $40,000 and $7,932,000, respectively.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

Other Segment

 

The Other Segment reflects intercompany eliminations, including significant intercompany eliminations of receivables and payables between the segments, cash and cash equivalents, all debt related activities, income tax activities and other corporate activities that are not allocated to the operating segments.

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

Credit Agreement Amendment

 

On October 2, 2009, CRLLC entered into a third amendment to its credit facility. The amendment was entered into primarily to provide financial flexibility to the Company through modifications to its financial covenants through the remaining term of the credit facility. Additionally, the amendment affords CVR the opportunity to incur indebtedness at the parent level by allowing for the parties to the credit agreement to distribute dividends to the parent in order to fund interest payments of up to $20,000,000 annually.

 

For purposes of the financial covenant calculations as of September 30, 2009, the Company utilized the requirements as set forth by the second amendment to the credit facility entered into on December 22, 2008. In connection with the third amendment, CRLLC incurred lender fees of approximately $2,558,000. These fees were recorded as deferred financing costs in the fourth quarter of 2009. In addition, CRLLC incurred third party costs of approximately $1,417,000 primarily consisting of administrative and legal costs. Of the third party costs incurred, the Company expensed approximately $414,000 in the third quarter of 2009 and approximately $537,000 in the fourth quarter of 2009. The remaining $466,000 was recognized as additional deferred financing costs with approximately $203,000 and $263,000 recorded in the third and fourth quarter of 2009, respectively. As described in Note 14, “Related Party Transactions,” a portion of the lender fees and third party costs were paid to separate subsidiaries of GS.

 

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes and with the statistical information and financial data appearing in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, as well as our Annual Report on Form 10-K for the year ended December 31, 2008. Results of operations for the three and nine months ended September 30, 2009 are not necessarily indicative of results to be attained for any other period.

 

Forward-Looking Statements

 

This Form 10-Q, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains “forward-looking statements” as defined by the Securities and Exchange Commission (the “SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:

 

 

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008. Such factors include, among others:

 

 

 

All forward-looking statements contained in this Form 10-Q speak only as of the date of this document. We undertake no obligation to update or revise publicly any forward-looking statements to reflect events or circumstances that occur after the date of this Form 10-Q, or to reflect the occurrence of unanticipated events.

 

Company Overview

 

CVR Energy, Inc. and, unless the context requires otherwise, its subsidiaries (“CVR”, the “Company”, “we”, “us” or “our”) is an independent refiner and marketer of high value transportation fuels. In addition, we currently own all of the interests (other than the managing general partner interest (“managing GP interest”) and associated incentive distribution rights (the “IDRs”)) in CVR Partners, LP (the “Partnership”) a limited partnership which produces nitrogen fertilizers, ammonia and urea ammonium nitrate (“UAN”).

 

Any references to the “Company” as of a date prior to October 16, 2007 and subsequent to June 24, 2005 are to Coffeyville Acquisition LLC (“CALLC”) and its subsidiaries. CALLC formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering, which was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”).

 

We operate under two business segments: petroleum and nitrogen fertilizer. Throughout the remainder of this document, our business segments are referred to as our “petroleum business” and our “nitrogen fertilizer business,” respectively.

 

Petroleum business.  Our petroleum business includes a 115,000 barrels per day (“bpd”) complex full coking medium-sour crude refinery in Coffeyville, Kansas. In addition to the refinery, we own and operate supporting businesses that include (1) a crude oil gathering system with a gathering capacity in excess of 30,000 bpd, serving central Kansas, northern Oklahoma, western Missouri, eastern Colorado and southwest Nebraska, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, (3) a 145,000 bpd pipeline system that transports crude oil to our refinery and associated crude oil storage tanks with a capacity of 1.2 million barrels and (4) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg and to customers at throughput terminals on Magellan Midstream Partners L.P.’s (“Magellan”) refined products distribution systems. We also lease 2.7 million barrels of storage capacity at Cushing, Oklahoma. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via the Magellan pipeline and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Operating, L.P. and NuStar Energy, L.P. Our refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Cushing is supplied by numerous

pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude oil variety in the world capable of being transported by pipeline.

 

Crude oil is supplied to our refinery through our owned and leased gathering system and by Plains Pipeline, L.P. pipeline from Cushing, Oklahoma. We also maintain capacity on the Spearhead Pipeline receiving crude oil from Canada and receive foreign and deepwater domestic crude oils via the Seaway Pipeline system. We also maintain leased storage in Cushing to facilitate optimal crude oil purchasing and blending. Our refinery blend consists of a combination of crude oil grades, including onshore and offshore domestic grades, various Canadian medium and heavy sours and sweet synthetics, and optionality of a variety of South American, North Sea, Middle East and West African imported grades. The access to a variety of crude oils coupled with the complexity of our refinery allows us to purchase crude oil at a discount to West Texas Intermediate (“WTI”). Our consumed crude cost discount to WTI for the third quarter of 2009 was $(2.82) per barrel compared to $(0.32) per barrel in the third quarter of 2008.

 

Nitrogen fertilizer business.  The nitrogen fertilizer business consists of a nitrogen fertilizer plant in Coffeyville, Kansas which includes two pet coke gasifiers. The nitrogen fertilizer plant is the only operation in North America utilizing a pet coke gasification process to produce nitrogen fertilizers (based on data provided by Blue Johnson & Associates). Its redundant train gasifier provides good on-stream reliability and with the use of low cost by-product pet coke feed, produces high purity hydrogen. This hydrogen is then converted to ammonia at a related ammonia synthesis plant. Ammonia is further upgraded into UAN solution in a related UAN unit. Pet coke is a low value by-product of the refinery coking process. On average during the last five years, more than 75% of the pet coke consumed by the nitrogen fertilizer plant was produced by our refinery. The nitrogen fertilizer business obtains most of its pet coke via a long-term coke supply agreement with our refinery.

 

The nitrogen fertilizer manufacturing facility is comprised of (1) an 84 million standard cubic foot per day gasifier complex, which consumes approximately 1,500 tons per day of pet coke to produce hydrogen, (2) a 1,225 ton-per-day ammonia unit and (3) a 2,025 ton-per-day UAN unit. In 2008, the nitrogen fertilizer business produced approximately 359,120 tons of ammonia, of which approximately 69% was upgraded into approximately 599,172 tons of UAN.

 

General Overview.  Due to the continued weakness of the general economy, including the tightness in the credit markets, and short-term tightening in demand of the petroleum and nitrogen fertilizer products, both the petroleum business and nitrogen fertilizer business are focused on controlling operational expenditures and minimizing capital spending while maintaining operational efficiency and safety. Inventory management practices are being employed to respond to the changes in demand levels which impact our production volumes in both businesses.

 

Major Influences on Results of Operations

 

Petroleum Business

 

Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control. These factors include the supply of, and demand for, crude oil, gasoline and other refined products which in turn depend on 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. Because we apply first-in, first-out, or FIFO, accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our 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 these 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 prices of

refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors’ facilities, price volatility, domestic and 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 refining 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.

 

In order to assess our operating performance, we compare our net sales, less cost of product sold against a widely used industry refining margin benchmark. The industry refining margin is calculated by assuming that two barrels of benchmark light sweet crude oil are converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread.

 

Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refinery has certain feedstock costs and logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect our margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that have historically cost less than WTI. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil and the price of WTI. The spread is referred to as our consumed crude differential. The consumed crude differential will move directionally with changes in the West Texas Sour crude oil (“WTS”) differential to WTI and the West Canadian Select (“WCS”) differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI, directly impacting refinery margin. The correlation between our consumed crude differential and published differentials will vary depending on the volume of medium sour crude and heavy 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 WTI less WCS differential was $9.21 and $18.69 per barrel, for the three months ended September 30, 2009 and 2008, respectively. The WTI less WTS differential was $1.81 and $2.31 per barrel for the three months ended September 30, 2009 and 2008, respectively. While the sweet-sour and heavy-sour crude oil markets remained tight during the third quarter of 2009, the related impact of this on our crude differential was offset in part due to the ongoing contango in the WTI crude oil market. Contango markets are characterized by prices for future delivery that are higher than the current or spot price of the commodity. Our quarterly crude oil costs benefited in the third quarter of 2009 from the ongoing contango. Our consumed crude oil less WTI differential was $(2.82) and $(0.32) per barrel for the three months ended September 30, 2009 and 2008, respectively.

 

We produce a significant volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices in our region include the logistics cost for U.S. Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact that the actual product specifications used to determine the NYMEX are different from the actual production in our refinery, is that prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra Low Sulfur Diesel basis. If gasoline and heating oil basis are greater than zero, this would mean that prices in our marketing area exceed those used in the 2-1-1 crack spread. Ultra Low Sulfur Diesel basis for the third quarter 2009 and 2008 averaged $1.97 and $4.68 per barrel, respectively. Gasoline basis for the third quarter 2009 averaged $(1.81) per barrel, compared to an average of $2.62 per barrel in the third quarter of 2008.

 

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices.

Consistent, safe, and reliable operations at our refinery are key to our financial performance and results of operations. Unplanned downtime at our refinery may result in lost margin opportunity, increased maintenance expense, a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The refinery generally undergoes a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The last refinery turnaround was completed in April 2007, and the next refinery turnaround is scheduled for the fourth quarter of 2011.

 

Because petroleum feedstocks and products are essentially commodities, we have no control over the changing market. Therefore, the lower target inventory position we are able to maintain significantly reduces the impact of commodity price volatility on our product 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 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 FIFO 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.

 

As the petroleum business continues to maintain high product output, product shipping logistics are beginning to surface as a potential limitation. We are continuing to evaluate and look at alternatives for shipping refined products out of the refinery. We do not expect any outbound transportation constraints to have a material or significant impact to the results of the operations of the petroleum business.

 

Nitrogen Fertilizer Business

 

In the nitrogen fertilizer business, earnings and cash flow from operations are primarily affected by the relationship between nitrogen fertilizer product prices and direct operating expenses. Unlike its competitors, our nitrogen fertilizer business uses minimal natural gas and, as a result, is not directly impacted in terms of cost by high or volatile swings in natural gas prices. Instead, our adjacent oil refinery supplies most of the pet coke feedstock needed pursuant to a long-term coke supply agreement we entered into in October 2007. The price paid by the nitrogen fertilizer business pursuant to the coke supply agreement with our refinery is based on the lesser of a coke price derived from the price received by the Partnership for UAN (subject to a UAN based price ceiling and floor) and a coke price index for pet coke.

 

The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the supply of, and the demand for, nitrogen fertilizer products. These factors depend on the price of natural gas, the 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 net sales of the nitrogen fertilizer business could fluctuate significantly with movements in natural gas prices during periods when fertilizer markets are weak and nitrogen fertilizer products sell at low prices, high natural gas prices do not force the nitrogen fertilizer business to shut down its operations as is the case with our competitors who rely heavily on natural gas instead of pet coke as a primary feedstock.

 

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 competitors’ facilities, price volatility, domestic and international political and economic developments and other factors 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.

The demand for nitrogen fertilizers is affected by the aggregate crop planting decisions and nitrogen fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of nitrogen fertilizer they apply depend on factors such as crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.

 

The United States Department of Agriculture reported on June 30, 2009 that growers planted an estimated 87 million acres of corn in 2009. This is the second largest planted acreage since 1946, behind 2007. The agricultural sector of the economy; however, has not remained entirely immune to the overall slowdown in both the domestic and world economies, and, in fact, fertilizer usage declined this year. A factor in this decline was the extremely wet weather experienced in the United States during the spring planting season.

 

In order to assess the operating performance of the nitrogen fertilizer business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs. Instead of experiencing high variability in the cost of raw materials, the nitrogen fertilizer business utilizes approximately 1% of the natural gas used by natural gas-based fertilizer producers.

 

Because the nitrogen fertilizer plant has certain logistical advantages relative to end users of ammonia and UAN and demand relative to our production has remained high, the nitrogen fertilizer business primarily targets end users in the U.S. farm belt where it incurs lower freight costs as compared to competitors. The nitrogen fertilizer business does not incur any barge or pipeline freight charges when it sells in these markets, giving us a distribution cost advantage over U.S. Gulf Coast importers. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.

 

The value of nitrogen fertilizer products is also an important consideration in understanding our results. During 2008, the nitrogen fertilizer business upgraded approximately 69% of its ammonia production into UAN, a product that presently generates a greater value than ammonia. UAN production is a major contributor to our profitability.

 

The direct operating expense structure of the nitrogen fertilizer business also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has significantly higher fixed costs than natural gas-based fertilizer plants. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, outside services, property taxes and insurance. These costs comprise the fixed costs associated with the nitrogen fertilizer plant.

 

Consistent, safe, and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense, 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.

 

The nitrogen fertilizer business generally undergoes a facility turnaround every two years. The turnaround typically lasts 15-20 days each turnaround year and costs approximately $3-5 million per turnaround. The facility underwent a turnaround in the fourth quarter of 2008, and the next facility turnaround is currently scheduled for the fourth quarter of 2010.

 

Factors Affecting Comparability of Our Financial Results

 

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.

Cash Flow Swap

 

Until October 8, 2009, Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR, had been a party to commodity derivative contracts (referred to as the “Cash Flow Swap”) with J. Aron & Company (“J. Aron”), a subsidiary of The Goldman Sachs Group, Inc. and a related party of ours. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. Based upon expected crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 14% of crude oil capacity for the period of July 1, 2009 through June 30, 2010. On October 8, 2009, the Cash Flow Swap was terminated and all remaining obligations were settled in advance. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under Financial Accounting Standards Board Accounting Standard Codification (“FASB ASC”) 815, Accounting for Derivative Instruments and Hedging Activities. As a result, the Consolidated Statement of Operations reflects all the realized and unrealized gains and losses from this swap which can create significant changes between periods.

 

For the three months ended September 30, 2009 and 2008, we recorded net realized and unrealized gains of $2.8 million and $65.2 million, respectively, related to the Cash Flow Swap. For the nine months ended September 30, 2009 and 2008, we recorded net realized and unrealized losses of $(55.6) million and $(38.7) million, respectively, related to the Cash Flow Swap. On July 1, 2009, the Cash Flow Swap decreased from approximately 5.9 million barrels per quarter to approximately 1.5 million barrels per quarter.

 

Share-Based Compensation

 

Through a wholly-owned subsidiary, we have two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. We account for awards under our Phantom Unit Plans as liability based awards. In accordance with FASB ASC 718, the expense associated with these awards for 2009 is based on the current fair value of the awards which was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of our common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled.

 

Also, in conjunction with the initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to the accounting guidance in FASB ASC 323, Accounting by an Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee and FASB ASC 505, Accounting for Equity Investments that Are Issued to Other than Employees for Acquiring or in Conjunction with Selling Goods or Services. In accordance with that accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived under the same methodology as the Phantom Unit Plans, as remeasured at each reporting date until the awards vest. For the three and nine months ended September 30, 2009, we increased compensation expense by $15.8 million and $25.1 million, respectively, as a result of the phantom and override unit share-based compensation awards. For the three and nine months ended September 30, 2008, we reversed compensation expense by $26.4 million and $37.7 million, respectively. We expect to incur continued incremental share-based compensation expense to the extent our common stock price continues to increase.

 

2007 Flood and Crude Oil Discharge

 

During the weekend of June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow its banks and flood the town of Coffeyville, Kansas. Our refinery and nitrogen fertilizer plant, which are located in close proximity to the Verdigris River, were severely flooded, sustained damage and required

repair. In addition to costs incurred for repairs to the Coffeyville facilities, we also incurred costs related to a discharge of crude oil from the facility that occurred on or about July 1, 2007.

 

We recorded pre-tax expenses, net of anticipated insurance recoveries of $0.5 million and $0.6 million in net costs associated with the flood for the three and nine months ended September 30, 2009, respectively, compared to pre-tax expenses, net of anticipated insurance recoveries of $(0.8) million and $8.8 million for the same period in 2008. The net costs have declined significantly over the comparable periods as the majority of repairs and maintenance to the facilities associated with damage caused by the flood were completed by the second quarter of 2008. In addition, the majority of the environmental remedial actions were substantially complete as of January 31, 2009.

 

Income Taxes

 

On an interim basis, income taxes are calculated based upon an estimated annual effective tax rate for the annual period. The estimated annual effective tax rate changes primarily due to changes in projected annual pre-tax income (loss) as estimated at each interim period and in correlation with federal and state income tax credits projected to be generated for the year. Significantly higher amounts of federal income tax credits were generated in 2008 related to the production of ultra-low sulfur diesel fuel, as well as significantly higher amounts of Kansas state income tax incentives generated under the High Performance Incentive Program (“HPIP”) in 2008. The decrease in the projected federal and state income tax credits generated for 2009 as compared to the level of projected pre-tax income, has increased the estimated annual effective tax rate for 2009 as compared to 2008. The decreased effective tax rate for the three months ended September 30, 2009 results from the 2009 estimated annual effective tax rate increasing during the third quarter due to increased non-deductible expenses associated with the increased levels of share-based compensation expense. This overall expected increase to the annual effective tax rate for 2009 generated a tax benefit at a lower effective tax rate on the pre-tax loss for the three months ended September 30, 2009.

Results of Operations

 

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three and nine months ended September 30, 2009 and 2008. The summary financial data for our two operating segments does not include certain selling, general and administrative expenses and depreciation and amortization related to our corporate offices. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” except for the balance sheet data as of December 31, 2008, is unaudited.