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)

 

 

(281) 207-3200

(Registrant’s telephone number, including area code)

 

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 86,343,102 shares of the registrant’s common stock outstanding at August 4, 2010.

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended June 30, 2010

 

 

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 distillate. 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 market — 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.

 

Coker unit — A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into pet coke.

 

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 market — Market situation in which prices for future delivery are higher than the current or spot market price of the commodity. The opposite of backwardation.

 

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 distillate.

 

Distillates — Primarily diesel fuel, kerosene and jet fuel.

 

Ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.

 

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 or Btu is 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 both feedstocks used in the manufacture of refined fuels and are products of the refining process. 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.

 

Spot market — A market in which commodities are bought and sold for cash and delivered immediately.

 

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 or transported on a pipeline.

 

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 — 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 degrees 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 oil 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

JUNE 30, 2010

(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 of high value transportation fuels 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 June 30, 2010 and December 31, 2009, approximately 64% 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 then 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 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 Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009.

 

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

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

the Partnership if it elects to pursue an initial public offering. In addition, the Partnership and its subsidiaries are currently guarantors under the first priority 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 first priority 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 June 30, 2010, 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, since an initial private or public offering of the Partnership was 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 recorded 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, 2009 audited consolidated financial statements and notes thereto included in CVR’s Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the SEC on March 12, 2010.

 

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 June 30, 2010 and December 31, 2009, the results of operations for the three and six months ended June 30, 2010 and 2009, and the cash flows for the six

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

months ended June 30, 2010 and 2009. Certain prior year amounts have been reclassified to conform to current year presentation.

 

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, 2010 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.

 

The Company evaluated subsequent events that would require an adjustment to the Company’s condensed consolidated financial statements or require disclosure in the notes to the condensed consolidated financial statements. The Company has evaluated subsequent events through the date of issuance of the condensed consolidated financial statements.

 

 

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, “Improving Disclosures about Fair Value Measurements” an amendment to Accounting Standards Codification (“ASC”) Topic 820, “Fair Value Measurements and Disclosures.” This amendment requires an entity to: (i) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, (ii) present separate information for Level 3 activity pertaining to gross purchases, sales, issuances, and settlements and (iii) enhance disclosures of assets and liabilities subject to fair value measurements. The provisions of ASU No. 2010-06 are effective for the Company for interim and annual reporting beginning after December 15, 2009, with one new disclosure effective after December 15, 2010. The Company adopted this ASU as of January 1, 2010. The adoption of this standard 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 was intended to improve financial reporting by enterprises involved with variable interest entities. Overall, the amendment revises the test for determining the primary beneficiary of a variable interest entity from a primarily quantitative analysis to a qualitative analysis. 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 adopted this standard as of January 1, 2010. The adoption of this standard did not impact the Company’s financial position or results of operations.

 

 

Prior to CVR’s initial public offering in October 2007, CVR’s subsidiaries were held and operated by CALLC. 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, CALLC, CALLC II and CALLC III account for share-based compensation in accordance with standards issued by the FASB regarding the treatment of share-based compensation, as well as guidance

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

regarding the accounting for share-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 these standards, CVR, CALLC, CALLC II and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. In addition, 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 issued by the FASB regarding the accounting for equity instruments 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 June 30, 2010, 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 the 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. As of June 30, 2010 all recipients of the override operating units issued to date were fully vested.

 

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:

 

 

(e) Override Units — Using a binomial and a probability-weighted expected return method that utilized CALLC III’s cash flow projections which includes expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. As a non-contributing investor, CVR also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is its percentage share of the contributed capital recognized by the investee) as

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

a result of the disproportionate funding of the compensation cost. As of June 30, 2010 these units were fully vested. Significant assumptions used in the valuation were as follows:

 

 

(f) Override Units — Using a probability-weighted expected return method that utilized CALLC III’s cash flow projections which includes expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. As a non-contributing investor, CVR also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. Of the 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units are subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows:

 

 

Based upon the estimated fair value at June 30, 2010, there was approximately $2,096,000 of unrecognized compensation expense related to non-voting override units. This expense is expected to be recognized over a remaining period of approximately one year 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 distributions when holders of override operating units receive distributions. Holders of performance phantom points have rights to receive distributions when CALLC and CALLC II 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 June 30, 2010, 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. The expense associated with these awards 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

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 $12.46 and $6.96 per point, respectively, at June 30, 2010. Using the June 30, 2009, 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 $14.27 and $7.69 per point, respectively. CVR has recorded approximately $8,366,000 and $6,723,000 in personnel accruals as of June 30, 2010 and December 31, 2009, respectively. Compensation expense for the three months ended June 30, 2010 related to the Phantom Unit Plans was reversed by $1,756,000. Compensation expense for the three months ended June 30, 2009 related to the Phantom Unit Plans was $2,603,000. Compensation expense for the six months ended June 30, 2010 and 2009 related to the Phantom Unit Plans was $1,643,000 and $4,498,000, respectively.

 

Based upon the estimated fair value at June 30, 2010, there was approximately $658,000 of unrecognized compensation expense related to the Phantom Unit Plans. This is expected to be recognized over a remaining period of approximately one year.

 

Long-Term Incentive Plan

 

CVR has a Long-Term Incentive Plan (“LTIP”) that permits the grant of options, stock appreciation rights, 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 June 30, 2010, there have been a total of 32,350 stock options granted, of which 18,536 have vested. During the three months ended June 30, 2010, 1,450 stock options vested and 3,149 stock options were forfeited. There were no grants of stock options for the six months ended June 30, 2010. The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. As of June 30, 2010, there was approximately $26,000 of total unrecognized compensation cost related to stock options to be recognized over a weighted-average period of approximately one year.

 

Non-Vested Stock

 

A summary of non-vested stock grant activity and changes during the six months ended June 30, 2010 is presented below:

 

 

Through the LTIP, shares of non-vested stock have been granted to employees and directors of the Company. Non-vested shares, when granted, are valued at the closing market price of CVR’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. These shares generally vest over a three-year period. As of June 30, 2010, there was

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

approximately $597,000 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 June 30, 2010 and 2009 related to the non-vested stock and stock options was $188,000 and $113,000, respectively. Compensation expense recorded for the six months ended June 30, 2010 and 2009 related to the non-vested stock and stock options was $361,000 and $215,000, 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):

 

 

 

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 June 30, 2010 and 2009, totaled approximately $766,000 and $389,000, respectively. Capitalized interest recognized as a reduction in interest expense for the six months ended June 30, 2010 and 2009, totaled approximately $1,647,000 and $802,000, respectively. Land and buildings that are under a capital lease obligation

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

approximated $4,827,000 as of June 30, 2010. 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 $738,000 and $719,000 for the three months ended June 30, 2010 and 2009, respectively. For the six months ended June 30, 2010 and 2009 cost of product sold excludes depreciation and amortization of $1,466,000 and $1,430,000, 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 exclude depreciation and amortization of $20,301,000 and $19,922,000 for the three months ended June 30, 2010 and 2009, respectively. For the six months ended June 30, 2010 and 2009 direct operating expenses exclude depreciation and amortization of $40,319,000 and $39,664,000, 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 exclude depreciation and amortization of $514,000 and $466,000 for the three months ended June 30, 2010 and 2009, respectively. For the six months ended June 30, 2010 and 2009, selling, general and administrative expenses exclude depreciation and amortization of $1,028,000 and $922,000, 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 insurance policies. The original balance of the note provided by the Company under such agreement was $10,000,000. As of June 30, 2010, the Company repaid the entire note obligation. As of December 31, 2009, the Company owed $7,500,000 related to this note.

 

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 2010, the Company renewed the lease for a one-year period commencing June 5, 2010. In connection with this capital lease, the Company makes quarterly lease payments that 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 $4,427,000 and $4,274,000 as of June 30, 2010 and December 31, 2009, respectively.

 

 

For the three months ended June 30, 2010 and 2009, the Company recorded pre-tax expenses, net of anticipated insurance recoveries of $0 and $(101,000), respectively, associated with the June/July 2007 flood and associated crude oil discharge. For the six months ended June 30, 2010 and 2009, the Company recorded pre-tax expenses, net of anticipated insurance recoveries of $0 and $80,000, 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 Condensed Consolidated Statements of Operations. 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

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

amount of $11,756,000, all property insurance claims and builders’ risk claims were fully settled, with all remaining claims closed under these policies only.

 

As of June 30, 2010, the remaining receivable from environmental insurance carriers was not anticipated to be collected in the next twelve months, and therefore has been classified as a non-current asset. 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 June 30, 2010, 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 generally subject to examination as of June 30, 2010 are 2006 to 2009. The United States Internal Revenue Service completed an examination of CVR and certain of its subsidiaries’ U.S. federal income tax returns for the tax year ended December 31, 2007 and also of a subsidiary for the tax year ended October 16, 2007. The examinations were concluded with no changes to the 2007 returns as filed.

 

The Company’s effective tax rate for the three and six months ended June 30, 2010 was (58.5)% and 42.0%, respectively, as compared to the Company’s combined federal and state expected statutory tax rate of 39.7%. The Company’s effective tax rate for the three and six months ended June 30, 2009 was 37.4% and 33.8%, respectively. The effective tax rate for the three and six months ended June 30, 2010 varies from the statutory rate primarily due to the receipt and recognition of interest income on federal income tax refunds received during the second quarter of 2010. The correlation of the recognition of the tax affected interest income with the pre-tax income and loss levels increased the effective tax rate of the tax benefit recorded for the periods in 2010. The effective tax rate for the three and six months ended June 30, 2009 was lower than the expected statutory tax rate due primarily to federal income tax credits available to small business refiners related to the production of ultra low sulfur diesel fuel. There have been no federal or state income tax credits included in the projected annualized effective tax rate for 2010.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

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

 

 

Outstanding stock options totaling 29,201 common shares were excluded from the diluted earnings (loss) per share calculation for the three and six months ended June 30, 2010, respectively, as they were antidilutive. Outstanding stock options totaling 32,350 common shares were excluded from the diluted earnings (loss) per share calculation for the three and six months ended June 30, 2009, respectively, as they were antidilutive. For the six months ended June 30, 2010, 173,715 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):

 

 

 

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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 June 30, 2010 and 2009, lease expense totaled $1,429,000 and $1,292,000, respectively. For the six months ended June 30, 2010 and 2009, lease expense totaled $2,621,000 and $2,481,000, 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

 

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 condensed consolidated financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

 

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 CRRM and other defendants between March 2009 and July 2009. In addition, in May 2010, separate groups of plaintiffs filed two lawsuits against CRRM and other defendants in federal court in Oklahoma and Kansas. All of the lawsuits allege that Samson or the other respective plaintiffs sold crude oil to a group of companies, which generally are known as SemCrude or SemGroup (collectively, “Sem”), which later declared bankruptcy and that Sem has not paid such plaintiffs for all of the crude oil purchased from Sem. The Samson lawsuits further allege that Sem sold some of the crude oil purchased from the plaintiffs to J. Aron & Company (“J. Aron”) and that J. Aron 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 the plaintiffs’ alleged claims are unknown since the price and amount of crude oil sold by the plaintiffs 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 and intends to vigorously defend against these claims.

 

The Company received a letter dated January 27, 2010, from the Litigation Trust formed pursuant to the Sem bankruptcy plan of reorganization claiming that $41,625,000 received by the Company from various Sem entities within the 90 day period prior to the Sem bankruptcy on July 22, 2008, may constitute recoverable preferences under the U.S. Bankruptcy Code. This claim has been settled in a manner favorable to the Company and the settlement will not have a material adverse effect on the condensed consolidated financial statements.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

See note (1) to the table at the beginning of this Note 11 (“Commitments and Contingent Liabilities”) for a discussion of the TransCanada litigation.

 

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 in 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.

 

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. By July 2008, the Company substantially completed remediating the damage caused by the crude oil discharge. 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.

 

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 nor can they 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 environmental and property 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 its 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, its 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 additional 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 Company has received $25,000,000 of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment to the Company of the primary pollution liability policy limit.

 

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

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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. 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 these locations.

 

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 June 30, 2010 and December 31, 2009, environmental accruals of $4,626,000 and $5,007,000, respectively, were reflected in the Condensed Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders and the VCPRP, for which $1,783,000 and $2,179,000, respectively, are included as other current liabilities. The Company’s accruals were determined based on an estimate of payment costs through 2031 and were discounted at the appropriate risk free rates at June 30, 2010 and December 31, 2009, respectively. The accruals include estimated closure and post-closure costs of $984,000 and $883,000 for two landfills at June 30, 2010 and December 31, 2009, respectively. The estimated future payments for these 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 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. In the second quarter of 2010, CRRM completed the installation of controls required to achieve compliance with the ULSG

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

standards. As such, beginning on January 1, 2011, CRRM will have fulfilled its remaining obligations under the “hardship waiver” (other than the final compliance report) and will be subject to all of the requirements of the ULSD and ULSG programs, without exception. CRRM will not report further on these programs unless there is a material change. Compliance with the Tier II gasoline and on-road diesel standards required the Company to spend approximately $20,589,000 during 2009, $13,787,000 during 2008, $16,800,000 during 2007 and $79,033,000 during 2006. Based on information currently available, CRRM anticipates spending approximately $13,985,000 in 2010 to comply with ULSG requirements. The entire amounts are expected to be capitalized. For the three months ended June 30, 2010 and 2009, CVR spent $2,831,000 and $3,633,000, respectively. For the six months ended June 30, 2010 and 2009, CVR spent $9,582,000 and $7,082,000, respectively.

 

In 2007, the EPA promulgated the Mobile Source Air Toxic II (“MSAT II”) rule, that requires the reduction of benzene in gasoline by 2011. CRRM is considered a small refiner under the MSAT II 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.

 

In February 2010, the EPA finalized changes to the Renewable Fuel Standards (“RFS2”) which require the total volume of renewable transportation fuels sold or introduced in the United States to reach 12.95 billion gallons in 2010 and rise to 36 billion gallons by 2022. Due to mandates in the RFS2 requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, there may be a decrease in demand for petroleum products. In addition, CRRM may be impacted by increased capital expenses and production costs to accommodate mandated renewable fuel volumes. CRRM’s small refiner status under the original Renewable Fuel Standards will continue under the RFS2 and therefore, CRRM is exempted from the requirements of the RFS2 through December 31, 2010. Beginning on January 1, 2011, CRRM will be required to begin blending renewable fuel into its gasoline and diesel fuel or purchase renewable energy credits (“RINs”) in lieu of blending.

 

In March 2004, CRRM and CRT entered into a Consent Decree (the “Consent Decree”) with the EPA and the Kansas Department of Health and Environment (the “KDHE”) to resolve air compliance concerns raised by the EPA and KDHE related to Farmland Industries, Inc.’s (“Farmland”) prior ownership and operation of the refinery. As a result of our agreement to install certain controls and implement certain operational changes, the EPA and KDHE agreed not to impose civil penalties, and provided a release from liability for Farmland’s alleged noncompliance with the issues addressed by the Consent Decree. Under the Consent Decree, CRRM agreed to install controls to reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its FCCU by January 1, 2011. In addition, pursuant to the Consent Decree, CRRM and CRT assumed cleanup obligations at the Coffeyville refinery and the Phillipsburg terminal facilities. The costs of complying with the Consent Decree are expected to be approximately $54 million, of which approximately $44 million is expected to be capital expenditures which do not include the cleanup obligations for historic contamination at the site that are being addressed pursuant to administrative orders issued under the RCRA. To date, CRRM and CRT have 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 may be unable to meet the Consent Decree’s January 1, 2011 deadline related to the installation of controls on the FCCU because of delays caused by the June/July 2007 flood. In February 2010, CRRM and the EPA agreed to a 15-month extension of the January 1, 2011 deadline for the installation of controls which was approved by the Court as a material modification to the existing Consent Decree. Pursuant to this agreement, CRRM will offset any incremental emissions resulting from the delay by providing additional controls to existing emission sources over a set timeframe.

 

Over the course of the last decade, the EPA has embarked on a national Petroleum Refining Initiative alleging industry-wide noncompliance with four “marquee” issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The Petroleum

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Refining Initiative has resulted in most refiners entering into consent decrees imposing civil penalties and requiring substantial expenditures for air pollution controls and enhanced operating procedures. The EPA has indicated that it will seek to have all refiners enter into “global settlements” pertaining to all “marquee” issues. The Company’s current Consent Decree covers some, but not all, of the “marquee” issues. We currently are in negotiations with EPA and KDHE under the Petroleum Refining Initiative. To date, the EPA has not made any specific claims or findings against us and we have not determined whether we will ultimately enter into a “global settlement” agreement with the EPA and KDHE. By entering into a “global settlement”, we may be able to extend the deadline for the installation of controls on the FCCU required under the 2004 Consent Decree. If we agree to enter into a global settlement we would be required to pay a civil penalty, but our incremental capital expenses would be limited primarily to the retrofit and replacement of heaters and boilers over a seven-year timeframe. EPA, KDHE and CRRM have reached an agreement in principle on most of the “marquee” issues and continue negotiations concerning the remaining issues.

 

On February 24, 2010, the Company received a letter from the United States Department of Justice on behalf of the EPA seeking a $900,000 civil penalty related to alleged late and incomplete reporting of air releases in violation of the Comprehensive Environmental Response, Compensation, and Liability Act and the Emergency Planning and Community Right to Know Act. The Company has reviewed and intends to contest the EPA’s allegations.

 

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended June 30, 2010 and 2009, capital environmental expenditures were $3,303,000 and $5,404,000, respectively. For the six months ended June 30, 2010 and 2009, capital environmental expenditures were $10,966,000 and $9,367,000, respectively. These expenditures were incurred to improve environmental compliance and efficiency of operations.

 

CRRM, CRNF, CRCT and CRT each believe it is 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 business, financial condition, or results of operations.

 

 

Long-term debt was as follows (in thousands):

 

 

Senior Secured Notes

 

On April 6, 2010, CRLLC and its newly formed wholly-owned subsidiary, Coffeyville Finance Inc. (together the “Issuers”), completed a private offering of $275,000,000 aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225,000,000 aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

the First Lien Notes, the “Notes”). At June 30, 2010, the estimated fair value of the First and Second Lien Notes was $275,250,000 and $219,375,000, respectively. These estimates of fair value were determined by quotations obtained from a broker-dealer who makes a market in these and similar securities. The Notes are fully and unconditionally guaranteed by each of CRLLC’s subsidiaries that also guarantee the first priority credit facility.

 

CRLLC received total net proceeds from the offering of approximately $485,693,000, net of underwriter fees of $10,000,000 and original issue discount of $4,020,000 and certain third party fees of $287,000. In addition, CRLLC incurred additional third party fees and expenses, net of write-offs and adjustments, totaling $3,600,000 associated with the offering. CRLLC applied the net proceeds to prepay all of the outstanding balance of its tranche D term loan under its first priority credit facility in an amount equal to $453,304,000 and to pay related fees and expenses. In accordance with the terms of its first priority credit facility, CRLLC paid a 2.0% premium totaling $9,066,000 to the lenders of the term debt upon the prepayment of the outstanding balance. This amount is recorded as a loss on extinguishment of debt during the second quarter of 2010. Additionally, due to the prepayment and termination of the term debt, a write-off of previously deferred financing charges of $5,380,000 is reflected in the Condensed Consolidated Statement of Operations as a loss on extinguishment of debt for the second quarter of 2010. The discount and related debt issuance costs of the Notes are being amortized over the term of the applicable Notes.

 

The First Lien Notes mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year commencing on October 1, 2010.

 

First Priority Credit Facility

 

Until April 6, 2010, CRLLC maintained tranche D term debt totaling $453,304,000. As documented above, this amount was paid in full with the proceeds of the issuance of the Notes. As of June 30, 2010 the first priority credit facility consisted of a $150,000,000 revolving credit facility. The revolving credit facility provides for direct cash borrowings for general corporate purposes and on a short-term basis. Letters of credit issued under the revolving credit facility are subject to a $100,000,000 sub-limit. Outstanding letters of credit reduce the amount available under the Company’s revolving credit facility. As of June 30, 2010, CRLLC had $30,761,000 of outstanding letters of credit consisting of: $193,000 in letters of credit in support of certain environmental obligations and $30,569,000 in letters of credit to secure transportation services for crude oil. The revolving loan commitment expires on December 28, 2012. As of June 30, 2010, the Company had no borrowings outstanding under the revolving credit facility and had aggregate availability of $119,239,000 under the revolving credit facility.

 

The first priority credit facility contains customary covenants and restrictions. As of June 30, 2010, the Company was in compliance with these covenants and restrictions under the first priority credit facility.

 

Included in other current liabilities on the Condensed Consolidated Balance Sheets is accrued interest payable $12,002,000 and $10,964,000 at June 30, 2010 and December 31, 2009, respectively. Of these amounts $11,462,000 and $10,588,000 are related to CRLLC’s Notes and credit facility borrowing arrangement at June 30, 2010 and December 31, 2009, respectively.

 

 

In September 2006, the FASB issued ASC 820 — Fair Value Measurements and Disclosures (“ASC 820”). ASC 820 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. 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.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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). ASC 820 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 June 30, 2010 and December 31, 2009 (in thousands):

 

 

As of June 30, 2010, 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. Additionally, the fair value of the Company’s Notes are disclosed in Note 12 (“Long-Term Debt”). Until June 30, 2010, the Company was a counterparty to the Interest Rate Swap (defined in Note 14 (“Derivative Financial Instruments”)). The Interest Rate Swap expired on June 30, 2010. Until expiration, the Company valued the financial statement position of the Interest Rate Swap using Level 2 inputs. The Company obtained broker quotations from the respective counterparties to the Interest Rate Swap. These quotations were derived from projected yield curves that considered inputs that included but were not limited to market risk, interest risk and credit risk. See Note 14 (“Derivative Financial Instruments”) for further discussion of the Interest Rate Swap. Given the degree of varying assumptions used to value the Interest Rate Swap, it was deemed as having Level 2 inputs. The Company’s commodity derivative contracts giving rise to a liability under Level 2 are valued using broker quoted market prices of similar commodity contracts. The Company had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2010. The carrying value of the

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Company’s long-term tranche D term debt held until April 6, 2010 approximated fair value as a result of floating interest rates assigned to this financial instrument.

 

 

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 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 was for the purpose of managing interest rate risk.

 

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

 

Cash Flow Swap

 

Until October 8, 2009, CRLLC had been a party to commodity derivative contracts (referred to as the “Cash Flow Swap”) that were originally executed on June 16, 2005. The swap agreements were executed at the prevailing market rate at the time of execution and were to provide an economic hedge on future transactions. The Cash Flow Swap resulted in unrealized gains (losses), using a valuation method that utilized quoted market prices. All of the activity related to the Cash Flow Swap is reported in the Petroleum Segment. 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, the third amendment to the Company’s first priority credit facility permitted early termination.

 

Interest Rate Swap

 

Until June 30, 2010, 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 from March 31, 2009 until March 31, 2010 and $110,000,000 million from March 31, 2010 until June 30, 2010. The Interest Rate Swap expired on June 30, 2010. Half of the Interest

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Rate Swap agreements were held with a related party (as described in Note 15, “Related Party Transactions”), and the other half were held with a financial institution that was also a lender under CRLLC’s first priority credit facility until April 6, 2010.

 

Under the Interest Rate Swap, CRLLC paid the fixed rate of 4.195% and received a floating rate based on three month LIBOR rates, with payments calculated on the notional amount. The notional amount did not represent the actual amount exchanged by the parties but instead represented the amount on which the contracts are based. The Interest Rate Swap was settled quarterly and marked to market at each reporting date with all unrealized gains and losses recognized in income. Transactions related to the Interest Rate Swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer segments.

 

 

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 the Cash Flow Swap with 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 14, “Derivative Financial Instruments”, the Cash Flow Swap was terminated by the parties effective October 8, 2009. For the three months ended June 30, 2009, the Company recognized net realized and unrealized losses totaling $22,577,000 related to these swap agreements which are reflected in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. For the six months ended June 30, 2009, the Company recognized net realized and unrealized losses totaling $58,406,000 related to these swap agreements, which are reflected in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

 

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 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 and the remaining deferral obligation of $62,375,000 including accrued interest of $509,000 was paid in the first quarter of 2009, resulting in the Company being unconditionally and irrevocably released from any and all of its obligations under the deferred agreements. In addition, J. Aron released the Goldman Sachs Funds and the Kelso Funds from any and all of their obligations to guarantee the deferred payment obligations. Interest expense related to the deferral agreement totaled $0 and $307,000 for the three and six months ended June 30, 2009, respectively.

 

Interest Rate Swap

 

On June 30, 2005, the Company also entered into three Interest Rate Swap agreements with J. Aron. Net losses for the three months ended June 30, 2010 related to these agreements were nominal. Net losses totaling $311,000 were recognized related to these swap agreements for the three months ended June 30, 2009 and are reflected in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. Net losses totaling $16,000 and $408,000 were recognized related to these swap agreements for the six months ended June 30, 2010 and 2009, respectively, and are reflected in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. In addition, the Condensed Consolidated Balance Sheet at June 30, 2010 and December 31, 2009 includes $0 and $1,415,000, respectively, in other current liabilities. See Note 14, (“Derivative Financial Instruments”) for additional information.

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Cash and Cash Equivalents

 

The Company holds a portion of its cash balance in a highly liquid money market account with average maturities of less than 90 days within the Goldman Sachs Funds family. As of June 30, 2010 and December 31, 2009, the balance in the account was approximately $25,000 and $723,000, respectively. For the three months ended June 30, 2010 and 2009, the account earned interest income of $2,000 and $29,000, respectively. For the six months ended June 30, 2010 and 2009, the account earned $2,000 and $44,000 of interest income, respectively.

 

Financing and Other

 

In March 2010, CRLLC amended its outstanding first priority credit facility. In connection with the amendment, CRLLC paid a subsidiary of GS fees and expenses of $904,500 for their services as lead bookrunner. In addition, on April 6, 2010, a subsidiary of GS received a fee as a participating underwriter of $2,000,000 upon completion of the issuance of the Notes (as described in Note 12 “Long-Term Debt”).

 

For the three months ended June 30, 2010 and 2009, the Company purchased approximately $38,000 and $38,000, respectively, of Fluid Catalytic Cracking Unit additives from Intercat, Inc. For the six months ended June 30, 2010 and 2009, the Company purchased approximately $276,000 and $115,000, respectively, of Fluid Catalytic Cracking Unit additives from Intercat, Inc. Mr. Regis Lippert, a director, and the President, CEO and majority shareholder of Intercat, Inc. was also a director of the Company until May 19, 2010.

 

For the three and six months ended June 30, 2010, the Company recognized approximately $372,000 and $393,000, respectively in expenses for the benefit of GS and Kelso in accordance with CVR’s Registration Rights Agreement. These amounts included registration and filing fees, printing fees, external accounting fees and external legal fees.

 

 

The Company measures segment profit as operating income for Petroleum and Nitrogen Fertilizer, CVR’s two reporting segments, based on the definitions provided in ASC 280 — Segment Reporting. All operations of the segments are located within the United States.

 

Petroleum

 

Principal products of the Petroleum Segment are refined fuels, propane and petroleum refining by-products including pet coke. The Petroleum Segment sells the pet coke to the Partnership for use in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For the Petroleum Segment, a per-ton transfer price is used to record intercompany sales on the part of the Petroleum Segment and a corresponding intercompany cost of product sold (exclusive of depreciation and amortization) is recorded 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 Nitrogen 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 $1,755,000 and $2,002,000 for the three months ended June 30, 2010 and 2009, respectively. Intercompany sales included in Petroleum net sales were $2,167,000 and $5,020,000 for the six months ended June 30, 2010 and 2009, 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 months ended June 30, 2010 and 2009 of $(565,000) and $(443,000), respectively. For the six months ended June 30, 2010 and 2009, the Petroleum Segment recorded intercompany costs of product sold (exclusive of depreciation and amortization) for hydrogen sales of $(1,133,000) and $215,000, respectively.

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 $574,000 and $2,549,000 for the three months ended June 30, 2010 and 2009, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was $1,012,000 and $6,085,000 for the six months ended June 30, 2010 and 2009, respectively.

 

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 cost of product sold (exclusive of depreciation and amortization) from intercompany hydrogen purchases of $565,000 and $1,133,000 for the three and six months ended June 30, 2010, respectively. For the three and six months ended June 30, 2009, the Nitrogen Fertilizer Segment recorded net sales generated from intercompany sales of hydrogen to the Petroleum Segment of $1,000 and $659,000, respectively, and recorded costs of product sold (exclusive of depreciation and amortization) of $444,000 and $444,000 for the three and six months ended June 30, 2009, respectively, for the purchase of intercompany hydrogen from the Petroleum Segment.

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Other Segment

 

The Other Segment reflects intercompany eliminations, 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)

 

 

 

Crude Oil Supply Agreement

 

On July 19, 2010, CRRM entered into an amendment to the Crude Oil Supply Agreement, dated December 2, 2008, as amended, with Vitol, Inc. (“Vitol”). The amendment extends the initial term of the Crude Oil Supply Agreement from three to four years ending December 31, 2012, whereby Vitol agrees to continue to provide crude oil supply and logistic intermediation on behalf of CRRM.

 

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 June 30, 2010, as well as our Annual Report on Form 10-K for the year ended December 31, 2009. Results of operations for the three and six months ended June 30, 2010 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, 2009 and in our From 10-Q for the quarter ended March 31, 2010. 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 and associated incentive distribution rights) in CVR Partners, LP (the “Partnership”), a limited partnership which produces nitrogen fertilizers, ammonia and 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 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas. In addition, supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 35,000 bpd serving Kansas, Oklahoma, western Missouri and southwestern Nebraska, (2) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg and at throughput terminals on Magellan’s refined products distribution systems, (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) storage and terminal facilities for refined fuels and asphalt in Phillipsburg, Kansas.

 

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. 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 Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Operating, L.P. and NuStar Energy, L.P.

 

Crude oil is supplied to our refinery through our gathering system and by a Plains pipeline from Cushing, Oklahoma. We maintain capacity on the Spearhead Pipeline from Canada and have access to foreign and deepwater domestic crude oil via the Seaway Pipeline system from the U.S. Gulf Coast to Cushing. 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 from time-to-time 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 WTI. Our crude consumed cost discount to WTI for the second quarter of 2010 was $(1.77) per barrel compared to $(6.38) per barrel in the second quarter of 2009.

 

Nitrogen fertilizer business.  The nitrogen fertilizer business consists of our interest in the Partnership, which is controlled by our affiliates. The nitrogen fertilizer business consists of a nitrogen fertilizer manufacturing facility, including (1) a 1,225 ton-per-day ammonia unit, (2) a 2,025 ton-per-day UAN unit and (3) a dual train gasifier complex each with a capacity of 84 million standard cubic feet per day, capable of processing approximately 1,400 tons per day of pet coke to produce hydrogen.

 

The nitrogen fertilizer plant in Coffeyville, Kansas includes two pet coke gasifiers that produce high purity hydrogen which in turn is converted to ammonia at a related ammonia synthesis plant. Ammonia is further upgraded into UAN solution in a related UAN unit. In 2009, the nitrogen fertilizer business produced 435,184 tons of ammonia, of which approximately 64% was upgraded into 677,739 tons of UAN. Pet coke is a low value by-product of the refinery coking process. On average during the last five years, 73% 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 pet coke supply agreement with the petroleum business.

 

The nitrogen fertilizer plant is the only commercial facility in North America utilizing a pet coke gasification process to produce nitrogen fertilizers. Its redundant train gasifier provides good on-stream reliability and uses low cost by-product pet coke feed (rather than natural gas) to produce hydrogen. In times of high natural gas prices, the use of low cost pet coke can provide us with a significant competitive advantage. The nitrogen fertilizer business’ competition utilizes natural gas to produce ammonia. Historically, pet coke has generally been a less expensive feedstock than natural gas on a per-ton of fertilizer produced basis.

 

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, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. 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, 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 addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuel standards, proposed climate change laws and regulations, and increased mileage standards for vehicles.

 

In order to assess our operating performance, we compare our net sales, less cost of product sold, or our refining margin, against an industry refining margin benchmark. The industry refining margin is calculated by assuming that two barrels of benchmark light sweet crude oil is 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. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold the benchmark production of gasoline and distillate.

 

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 refinery margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has 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 oil differential. Our refinery margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the 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. The correlation between our consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil we purchase as a percent of our total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.

 

We produce a high 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 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 both gasoline and Ultra Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.

 

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 and 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.

 

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

 

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, the nitrogen fertilizer business uses minimal natural gas as feedstock and, as a result, is not directly impacted in terms of cost, by volatile swings in natural gas prices. Instead, our adjacent refinery supplies most of the pet coke feedstock needed by the nitrogen fertilizer business pursuant to a long-term pet coke supply agreement we entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends 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. Nitrogen fertilizer prices are also affected by other factors, such as local market conditions and the operating levels of competing facilities. An expansion or upgrade of competitors’ facilities, 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.

 

In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and 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 fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.

 

Natural gas is the most significant raw material required in our competitors’ production of nitrogen fertilizers. Over the past several years, natural gas prices have experienced high levels of price volatility. This pricing and volatility has a direct impact on our competitors’ cost of producing nitrogen fertilizer.

 

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.

 

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 U.S. Gulf Coast 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 producers and 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 2009, the nitrogen fertilizer business upgraded approximately 64% 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, and outside services. These costs comprise the fixed costs associated with the nitrogen fertilizer plant.

 

The nitrogen fertilizer business’ largest raw material expense is pet coke, which it purchases from the petroleum business and third parties. In 2009, the nitrogen fertilizer business spent $12.8 million for pet coke. If pet coke prices rise substantially in the future, the nitrogen fertilizer business may be unable to increase its prices to recover increased raw material costs, because the price floor for nitrogen fertilizer products is generally correlated with natural gas prices, the primary raw material used by its competitors, and not pet coke prices.

 

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 and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $3 million to $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, CRLLC had been a party to the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. and a related party of ours. 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 did not qualify as a hedge for hedge accounting treatment under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging. As a result, the Consolidated Statement of Operations reflects all the realized and unrealized gains and losses from this swap which has created significant changes between periods. As a result of the termination of the Cash Flow Swap in the fourth quarter of 2009, there was no impact recorded in the three and six months ended June 30, 2010 compared to net realized and unrealized losses of $22.6 million and $58.4 million for the three and six months ended June 30, 2009.

 

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, Compensation — Stock Compensation, the expense associated with these awards 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 an accounting standard issued by the FASB which provides guidance regarding the accounting treatment by an investor for stock-based compensation granted to employees of an equity method investee. In addition, these awards are subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment for equity instruments that are issued to other than employees for acquiring or in conjunction with selling goods or services. In accordance with this 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 months ended June 30, 2010, we reversed compensation expense by $3.0 million as a result of the phantom and override unit share-based compensation awards. For the three months ended June 30, 2009, we increased compensation expense by $5.5 million, as a result of the phantom and override unit share-based compensation awards. For the six months ended June 30, 2010 and 2009, we increased compensation expense by $4.1 million and $9.3 million, respectively, as a result of the phantom and override unit share-based compensation awards. We expect to incur additional incremental share-based compensation expense to the extent our common stock price increases.

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 six months ended June 30, 2010 and 2009. 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, 2009, is unaudited.