CVR ENERGY INC - Quarter Report: 2011 June (Form 10-Q)

 

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 of 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 þ     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 86,573,498 shares of the registrant’s common stock outstanding at August 2, 2011.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended June 30, 2011

 

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 capacity. 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.

 

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.

 

corn belt — The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin.

 

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, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.

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:  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.

 

plant gate price — the unit price of fertilizer, in dollars per ton, offered on a delivered basis and excluding shipment costs.

 

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 inspect, refurbish, repair and maintain the refinery or nitrogen fertilizer plant assets. This process involves the shutdown and inspection of major processing units and occurs every four to five years for the refinery and every two years for the nitrogen fertilizer plant.

 

UAN — An aqueous solution of urea and ammonium nitrate used as a fertilizer.

 

wheat belt — The primary wheat producing region of the United States, which includes Oklahoma, Kansas, North Dakota, South Dakota and Texas.

 

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 between 30 and 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.

 

 

 

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

 

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

 

 

See accompanying notes to the condensed consolidated financial statements.

CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

 

 

Organization

 

The “Company” or “CVR” may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, 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 wholly-owned subsidiaries, owns the general partner and 69.8% of the common units of CVR Partners, LP, a publicly-traded partnership which 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.

 

CVR’s common stock is listed on the New York Stock Exchange under the symbol “CVI.” As of December 31, 2010, approximately 40% 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”). On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold into the public market its remaining ownership interests in CVR and Kelso substantially reduced its interest in the Company. On May 26, 2011, Kelso completed a registered public offering, whereby Kelso sold into the public market its remaining ownership interests in CVR Energy.

 

Nitrogen Fertilizer Limited Partnership

 

In conjunction with the consummation of CVR’s initial public offering in 2007, CVR transferred Coffeyville Resources Nitrogen Fertilizers, 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 (“LP interest,” represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest, including the associated incentive distribution rights (“IDRs”), to Coffeyville Acquisition III LLC (“CALLC III”), an entity owned by its then 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 $10.6 million. This interest has been classified as a noncontrolling interest included as a separate component of equity in the Condensed Consolidated Balance Sheets at December 31, 2010. In connection with the April 2011 initial public offering of the Partnership (the “Offering”), as discussed in further detail below, the IDRs were purchased by the Partnership and the IDRs were subsequently extinguished. In addition, the noncontrolling interest representing the managing GP interest was purchased by Coffeyville Resources, LLC (“CRLLC”), a subsidiary of CVR. The payment for the IDRs was paid to the owners of CALLC III, which included the Goldman Sachs Funds, the Kelso Funds and members of CVR senior management. As a result of the Offering, the Company recorded a noncontrolling interest for the common units sold into the public market which represented approximately a 30.2% interest in the Partnership at the time of the Offering. The Company’s noncontrolling interest reflected on the consolidated balance sheet of CVR will be impacted by the net income of, and distributions from the Partnership.

 

On April 13, 2011, the Partnership completed its initial public offering (the “Offering”) of 22,080,000 common units priced at $16.00 per unit (such amount includes common units issued pursuant to the exercise

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

of the underwriters’ over-allotment option). The common units, which are listed on the New York Stock Exchange, began trading on April 8, 2011 under the symbol “UAN”.

 

At June 30, 2011, the Partnership had 73,002,956 common units outstanding, consisting of 22,082,956 common units owned by the public, representing 30.2% of the total Partnership units and 50,920,000 common units owned by CRLLC, representing 69.8% of the total Partnership units.

 

The gross proceeds to the Partnership from the Offering (including the gross proceeds from the exercise of the underwriter’s over-allotment option) were approximately $353.3 million before giving effect to underwriting discounts and commissions and offering expenses. In connection with the Offering, the Partnership paid approximately $24.7 million in underwriting fees and incurred approximately $4.4 million of other offering costs. Approximately $5.7 million of the underwriting fee was paid to an affiliate of GS, which was acting as a joint book-running manager for the Offering. Until completion of CVR’s February 2011 secondary offering, an affiliate of GS was a stockholder and related party of the Company. As a result of the Offering and as of the date of this Report, CVR indirectly owns 69.8% of the Partnership’s outstanding common units and 100% of the Partnership’s general partner, CVR GP, LLC, which only holds a non-economic interest.

 

In connection with the Offering, the Partnership’s limited partner interests were converted into common units, the Partnership’s special general partner interests were converted into common units, and the Partnership’s special general partner was merged with and into CRLLC, with CRLLC continuing as the surviving entity. In addition, as discussed above, the managing general partner sold its IDRs to the Partnership for $26.0 million, these interests were extinguished, and CALLC III sold the managing general partner to CRLLC for a nominal amount. As a result of the Offering, the Partnership has two types of partnership interests outstanding:

 

 

The proceeds from the Offering were utilized as follows:

 

 

The Partnership intends to make quarterly cash distributions of all available cash generated each quarter beginning with the quarter ended June 30, 2011, covering the period from the closing of the Offering through June 30, 2011 to common unitholders. The available cash for each quarter will be determined by the board of directors of the Partnership’s general partner. The partnership agreement does not require that the Partnership

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

make cash distributions on a quarterly or other basis. In connection with the Offering, the board of directors of the general partner adopted a distribution policy, which it may change at any time.

 

The Partnership is operated by CVR’s senior management (together with other officers of the general partner) pursuant to a services agreement among CVR, the general partner and the Partnership. The Partnership’s general partner, CVR GP, LLC, manages the operations and activities of the Partnership, subject to the terms and conditions specified in the partnership agreement. The operations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in its individual capacity will be made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The general partner is not elected by the common unitholders and is not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business of the Partnership. CVR, the Partnership, their respective subsidiaries and the general partner are parties to a number of agreements to regulate certain business relations between them. Certain of these agreements were amended in connection with the Offering.

 

Basis of Consolidation

 

Prior to the Offering of the Partnership, management had determined that the Partnership was a variable interest entity (“VIE”) and as such evaluated the qualitative criteria under Accounting Standards Codification (“ASC”) Topic 810-10 — Consolidations-Variable Interest Entities (“ASC 810-10”), to make a determination whether CVR Partners should be consolidated on the Company’s financial statements. ASC 810-10 requires the primary beneficiary of a variable interest entity’s activities to consolidate the VIE. The primary beneficiary is identified as the enterprise that has a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and b) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. The standard requires an ongoing analysis to determine whether the variable interest gives rise to a controlling financial interest in the VIE.

 

Subsequent to the Offering of the Partnership, the Partnership is no longer considered a VIE. The consolidation of the Partnership is based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR; and, therefore, CVR has the ability to control the activities of the Partnership. Additionally, the Partnership’s general partner manages the operations and activities of the Partnership, subject to the terms and conditions specified in the partnership agreement. The operations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in its individual capacity will be made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The general partner is not elected by the common unitholders of the Partnership and is not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business. All but one of the officers of the general partner are also officers of CVR. Based upon the general partnership’s role and rights as afforded by the partnership agreement and the limited rights afforded to the limited partners the consolidated financial statements of CVR will include the assets, liabilities, cash flows, revenues and expenses of the Partnership.

 

The limited rights of the common unitholders of the Partnership are demonstrated by the fact that the common unitholders have no right to elect the general partner or the general partner’s directors on an annual or other continuing basis. The general partner can only be removed by a vote of the holders of at least 662/3% of the outstanding common units, including any common units owned by the general partner and its affiliates (including CRLLC, a wholly-owned subsidiary of CVR) voting together as a single class.

 

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

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

of the Securities and Exchange Commission (“SEC”). The condensed 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, 2010 audited consolidated financial statements and notes thereto included in CVR’s Annual Report on Form 10-K for the year ended December 31, 2010, which was filed with the SEC on March 7, 2011.

 

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, 2011 and December 31, 2010, the results of operations of the Company for the three and six months ended June 30, 2011 and 2010, and cash flows for the six months ended June 30, 2011 and 2010.

 

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, 2011 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, if any, that would require an adjustment or would require disclosure to the Company’s condensed consolidated financial statements through the date of issuance of these condensed consolidated financial statements.

 

 

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. The Company believes that the adoption of this standard will not materially expand its consolidated financial statement footnote disclosures.

 

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income,” (“ASU 2011-05”) which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 will be effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. The adoption of ASU 2011-05 will not have a material impact on the Company’s consolidated financial statements.

 

 

Prior to CVR’s initial public offering in October 2007, CVR’s subsidiaries were held and operated by Coffeyville Acquisition LLC (“CALLC”) and its subsidiaries. Management of CVR held an equity interest in

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 in October 2007, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“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 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.

 

The fair value of the CALLC III override units for the three months ended June 30, 2011 was derived based upon the value, resulting from the proceeds received by the general partner upon the purchase of the IDR’s by the Partnership. These proceeds were subsequently distributed to the owners of CALLC III which includes the override unitholders. This value was utilized to determine the related compensation expense for the unvested units. For the three and six months ended June 30, 2010, the estimated fair value of the override units of CALLC III were determined using a probability-weighted expected return method which utilized CALLC III’s cash flow projections, which were considered representative of the nature of interests held by CALLC III in the Partnership.

 

In February 2011, CALLC and CALLC II sold into the public market 11,759,023 shares and 15,113,254 shares, respectively, of CVR’s common stock, pursuant to a registered public offering. As a result of this offering, CALLC reduced its beneficial ownership in the Company to approximately 9% of its outstanding shares and CALLC II was no longer a stockholder of the Company. Subsequent to CALLC II’s divestiture of its ownership interest in the Company, no additional share-based compensation expense was incurred with respect to override units and phantom units associated with CALLC II.

 

In May 2011, CALLC sold into the public market 7,998,179 shares of CVR’s common stock, pursuant to a registered public offering. As a result, CALLC is no longer a stockholder of the Company. Subsequent to CALLC’s divestiture of its ownership interest in the Company, no additional share-based compensation expense will be incurred with respect to override units and phantom units associated with CALLC.

 

The fair value of the override units of CALLC was derived based upon the value resulting from the proceeds received associated with CALLC’s divestiture of its ownership in CVR. This value was utilized to determine the related compensation expense for the unvested units. The probability-weighted expected return method was also used to determine the estimated fair value of the override units of CALLC and CALLC II for the three and six months ended June 30, 2010. 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

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 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.

 

 

Due to the divestiture of all ownership in CVR by CALLC and CALLC II and due to the purchase of IDRs from the general partner and the distribution to CALLC III, there is no associated unrecognized compensation expense as of June 30, 2011.

 

Valuation Assumptions

 

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

 

 

As of June 30, 2010, all of the recipients of the override operating units were fully vested.

 

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

 

 

(e) Override Units — Using a binomial and a probability-weighted expected return method which utilized CALLC III’s cash flow projections and included expected future earnings and the anticipated timing of IDRs,

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 had 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. As of June 30, 2011 these units were fully vested.

 

(f) Override Units — Using a probability-weighted expected return method which utilized CALLC III’s cash flow projections and included 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 had 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:

 

 

Phantom Unit Appreciation 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 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 plans expire on July 25, 2015, or at the discretion of CVR.

 

The expense associated with these awards is based on the current fair value of the awards which historically has been derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of the Company’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled.

 

CVR has recorded approximately $0 and approximately $18.7 million in personnel accruals as of June 30, 2011 and December 31, 2010, respectively. Compensation expense for the three months ended June 30, 2011 related to the Phantom Unit Plans was reversed by approximately $0.7 million. Compensation expense for the three months ended June 30, 2010 related to the Phantom Unit Plans was reversed by approximately $1.8 million. Compensation expense for the six months ended June 30, 2011 and 2010 related to the Phantom Unit Plans was approximately $10.6 million and $1.6 million, respectively.

 

As described above, in February 2011, CALLC and CALLC II completed a sale of CVR common stock into the public market pursuant to a registered public offering. As a result of this offering, the Company made a payment to phantom unitholders of approximately $20.1 million in the first quarter of 2011. As described above, in May 2011, CALLC completed an additional sale of CVR common stock into the public market pursuant to a registered public offering. As a result of this offering, the Company made a payment to phantom unitholders of approximately $9.2 million in the second quarter of 2011.

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Due to the divestiture of all ownership of CVR by CALLC and CALLC II and the associated payments to the holders of service and phantom performance points, there is no unrecognized compensation expense at June 30, 2011.

 

Using the Company’s closing stock price at June 30, 2010, to determine the Company’s equity value, through an independent valuation process, the service phantom interest and performance phantom interest were valued as follows:

 

 

Long-Term Incentive Plan

 

CVR has a Long-Term Incentive Plan (“LTIP”) which permits the grant of options, stock appreciation rights, restricted shares, restricted share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). As of June 30, 2011, only restricted shares of CVR common stock and stock options had been granted under the LTIP. Individuals who are eligible to receive awards and grants under the LTIP include the Company’s employees, officers, consultants, advisors and directors.

 

Stock Options

 

As of June 30, 2011, there have been a total of 32,350 stock options granted, of which 26,168 have vested. However, 6,301 vested options have expired resulting in a net total of 19,867 outstanding options that have vested. Additionally, 3,149 unvested stock options were forfeited in the second quarter of 2010. There were 1,450 options that vested in the second quarter of 2011. There were no options forfeited or granted in the second quarter of 2011. The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. As of June 30, 2011, there was approximately $1,600 of total unrecognized compensation cost related to stock options which will be fully recognized in the third quarter of 2011 upon vesting.

 

Restricted Stock

 

A summary of restricted stock grant activity and changes during the six months ended June 30, 2011 is presented below:

 

 

Through the LTIP, restricted shares have been granted to employees of the Company. Restricted 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, 2011, there was approximately $8.9 million of total

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unrecognized compensation cost related to restricted shares to be recognized over a weighted-average period of approximately two years.

 

Compensation expense recorded for the three months ended June 30, 2011 and 2010 related to the restricted shares and stock options was approximately $2.5 million and $0.2 million, respectively. Compensation expense recorded for the six months ended June 30, 2011 and 2010 related to the restricted shares and stock options was approximately $4.7 million and $0.4 million, respectively.

 

CVR Partners’ Long-Term Incentive Plan

 

In connection with the Offering, the board of directors of the general partner adopted the CVR Partners, LP Long-Term Incentive Plan (“CVR Partners’ LTIP”). Individuals who are eligible to receive awards under the CVR Partners’ LTIP include CVR Partners’, its subsidiaries’ and its parent’s employees, officers, consultants and directors. The CVR Partners’ LTIP provides for the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards, each in respect of common units. The maximum number of common units issuable under the CVR Partners’ LTIP is 5,000,000.

 

In connection with the Offering, 23,448 phantom units were granted to certain board members of the Partnership’s general partner. These phantom units are expected to vest six months following the grant date. These phantom unit awards granted to the directors of the general partner are considered non-employee equity-based awards since the directors are not elected by unitholders. These phantom unit director awards are required to be marked-to-market each reporting period until they are vested.

 

In June 2011, 50,659 phantom units were granted to an employee of the general partner. These phantom units are expected to vest over three years on the basis of one-third of the award each year. As this phantom award, which is an equity-based award, was granted to an employee of a subsidiary of the Company, it was valued at the closing unit price of the Partnership’s common units on the date of grant and will be amortized to compensation expense on a straight-line basis over the vesting period of the award.

 

In June 2011, 2,956 fully vested common units were granted to certain board members of the general partner. The fair value of these awards was calculated using the closing price of the Partnership’s common units on the date of grant. This amount was fully expensed at the time of grant.

 

Compensation expense recorded for the three months ended June 30, 2011 and 2010, related to the awards under the CVR Partners’ LTIP was approximately $0.3 million and $0, respectively. Compensation expense recorded for the six months ended June 30, 2011 and 2010, related to the awards under the CVR Partners’ LTIP was approximately $0.3 million and $0, respectively. Compensation expense associated with the awards under the CVR Partners’ LTIP has been recorded in selling, general and administrative expenses (exclusive of depreciation and amortization).

 

As of June 30, 2011, there were 4,922,937 common units available for issuance under the CVR Partners’ LTIP. Unrecognized compensation expense associated with the unvested phantom units at June 30, 2011 was approximately $1.2 million.

 

 

Inventories consist primarily of domestic and foreign 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

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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:

 

 

 

A summary of costs for property, plant, and equipment is as follows:

 

 

Capitalized interest recognized as a reduction in interest expense for the three months ended June 30, 2011 and 2010 totaled approximately $0.8 million in both periods. Capitalized interest recognized as a reduction in interest expense for the six months ended June 30, 2011 and 2010, totaled approximately $0.9 million and $1.6 million, respectively. Buildings and equipment that are under a capital lease obligation approximated $0.3 million as of June 30, 2011. 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 approximately $0.6 million and $0.7 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, cost of product sold excludes depreciation and amortization of approximately $1.3 million and $1.5 million, respectively.

 

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses exclude depreciation and amortization of approximately

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

$20.9 million and $20.3 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, direct operating expenses exclude depreciation and amortization of approximately $41.8 million and $40.3 million, respectively.

 

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal, treasury, accounting, marketing, human resources and costs associated with maintaining the corporate and administrative office in Texas and the administrative office in Kansas. Selling, general and administrative expenses exclude depreciation and amortization of approximately $0.5 million for both of the three months ended June 30, 2011 and 2010. For the six months ended June 30, 2011 and 2010, selling, general and administrative expenses exclude depreciation and amortization of approximately $1.0 million and $1.0 million, respectively.

 

 

The Company entered into an insurance premium finance agreement in July 2010 to finance a portion of the purchase of its 2010/2011 property insurance policies. The original balance of the note provided by the Company under such agreement was approximately $5.0 million. The Company began to repay this note in equal installments commencing October 1, 2010. As of June 30, 2011 and December 31, 2010, the Company owed $0 and approximately $3.1 million, respectively, related to this note.

 

From time to time, the Company enters lease agreements for purposes of acquiring assets used in the normal course of business. The majority of the Company’s leases are accounted for as operating leases. During 2010, the Company entered two lease agreements for information technology equipment that are accounted for as capital leases. The initial capital lease obligation of these agreements totaled approximately $0.4 million. The two capital leases entered into during 2010 have terms of 12 and 36 months. As of June 30, 2011, the outstanding capital lease obligation associated with these leases totaled $0.2 million.

 

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. The Company was obligated to make quarterly lease payments that totaled approximately $0.1 million annually. The Company also had the option to purchase the property during the term of the lease, including the renewal periods. The capital lease obligation was approximately $4.6 million as of December 31, 2010. In March 2011, the Company exercised its purchase option and paid approximately $4.7 million to satisfy the lease obligation.

 

 

Nitrogen Fertilizer Incident

 

On September 30, 2010, the nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. All operations at the nitrogen fertilizer facility were immediately shut down. No one was injured in the incident. Repairs to the facility as a result of the rupture were substantially complete as of December 31, 2010.

 

Total gross costs recorded as of June 30, 2011 due to the incident were approximately $11.1 million for repairs and maintenance and other associated costs. Approximately $0.2 million of these costs was recognized during the three months ended June 30, 2011. Approximately $0.6 million of these costs was recognized during the six months ended June 30, 2011. The repairs and maintenance costs incurred are included in direct operating expenses (exclusive of depreciation and amortization). Of the costs incurred approximately $4.5 million was capitalized.

 

The Company maintains property damage insurance policies which have an associated deductible of $2.5 million. The Company anticipates that substantially all of the repair costs in excess of the $2.5 million

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deductible should be covered by insurance. These insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs the Company has incurred relating to the damage and losses suffered for business interruption. This coverage, however, only applies to losses incurred after a business interruption of 45 days. In connection with the incident, the Company recorded an insurance receivable of approximately $4.5 million, of which approximately $4.3 million of insurance proceeds was received in December 2010 and the remaining approximately $0.2 million was received in January 2011. The recording of the insurance receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).

 

In the first quarter of 2011, the Company submitted a partial business interruption claim for damages and losses, as afforded by its insurance policies. The Company’s insurance carriers agreed to make interim payments totaling approximately $2.9 million. Insurance proceeds were received totaling approximately $2.3 million related to the business interruption claim through March 31, 2011 and the Company received the remaining approximate $0.6 million in April 2011. The proceeds associated with the business interruption claim are included on the Condensed Consolidated Statements of Operations under Insurance recovery — business interruption.

 

Refinery Incidents

 

On December 28, 2010 the crude oil refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit (“FCCU”), which led to reduced crude throughput. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. Total gross repair and other costs recorded related to the incident as of June 30, 2011 were approximately $8.1 million. No costs were recorded during the three months ended June 30, 2011. As documented above, the Company maintains property damage insurance policies which have an associated deductible of $2.5 million. The Company anticipates that substantially all of the costs in excess of the deductible should be covered by insurance. As of June 30, 2011, the Company has recorded an insurance receivable related to the incident of approximately $5.2 million. The insurance receivable is included in other current assets in the Condensed Consolidated Balance Sheet. The recording of the insurance receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).

 

The crude oil refinery experienced a small fire at its continuous catalytic reformer (“CCR”) in May 2011. Total gross repair and other costs recorded related to the incident for the three months ended June 30, 2011 approximated $3.1 million. The Company anticipates that substantially all of the costs in excess of the $2.5 million deductible should be covered by insurance under its property damage insurance policy. As of June 30, 2011, the Company has recorded an insurance receivable of approximately $0.6 million. The insurance receivable is included in other current assets in the Condensed Consolidated Balance Sheet. The recording of the insurance receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).

 

 

The Company recognizes liabilities, interest and penalties for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due as determined under ASC Topic 740 — Income Taxes. In the second quarter of 2011, the Company recorded approximately $17.5 million associated with uncertain tax positions. As of June 30, 2011, the Company had unrecognized tax benefits of approximately $0.2 million which, if recognized, would impact the Company’s effective tax rate. Unrecognized tax benefits that are not expected to be settled within the next twelve months are included in other long-term liabilities in the condensed consolidated balance sheet; unrecognized tax benefits that are expected to be settled within the next twelve months are included in income taxes payable. The Company has not accrued any amounts for

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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. At June 30, 2011, the Company’s tax filings are generally open to examination in the United States for the tax years ended December 31, 2008 through December 31, 2010 and in various individual states for the tax years ended December 31, 2007 through December 31, 2010.

 

The Company’s effective tax rate for the three and six months ended June 30, 2011 was 36.38% and 36.59%, 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, 2011 is lower than the statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interest of CVR Partners, LP’s earnings beginning April 13, 2011, as well as benefits for domestic production activities. The Company’s effective tax rate for the three and six months ended June 30, 2010 was (58.5%) and 42%, respectively. The Company’s 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 effected interest income with the pre-tax income and loss levels increased the effected tax rate of the tax benefit recorded for the periods in 2010.

 

 

Basic and diluted earnings per share are computed by dividing net income (loss) attributable to CVR Energy stockholders 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 19,099 and 29,201 common shares were excluded from the diluted earnings per share calculation for the six months ended June 30, 2011 and 2010, respectively, as they were antidilutive. Outstanding stock options totaling 18,597 and 29,201 common shares were excluded from the diluted earnings per share calculation for the three months ended June 30, 2011 and 2010, respectively, as they were antidilutive. For the six months ended June 30, 2010, 173,715 shares of restricted common stock were excluded from the diluted earnings (loss) per share calculation, as they were antidilutive.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

Leases and Unconditional Purchase Obligations

 

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

 

 

 

 

The Company leases various equipment, including rail cars, and real properties under long-term operating leases, expiring at various dates. For the three months ended June 30, 2011 and 2010, lease expense totaled approximately $1.3 million and $1.4 million, respectively. For the six months ended June 30, 2011 and 2010, lease expense totaled approximately $2.6 million and $2.6 million, 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, storage, utilities 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. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. 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.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 state court in Oklahoma and Kansas. All of the lawsuits filed in state court were removed to federal court. All of the lawsuits (except for the New Mexico suits, which remained in federal court in New Mexico) were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware, where the Sem Group bankruptcy resides. In March 2011, CRRM was dismissed without prejudice from the New Mexico suits. All of the lawsuits allege that Samson or 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 Samson 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 is 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. On January 26, 2011, CRRM and J. Aron entered into an agreement whereby J. Aron agreed to indemnify and defend CRRM from any damage, out-of-pocket expense or loss in connection with any crude oil involved in the lawsuits which CRRM purchased through J. Aron, and J. Aron agreed to reimburse CRRM’s prior attorney fees and out-of-pocket expenses in connection with the lawsuits.

 

CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with its construction that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed CRNF’s nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment has resulted in an increase to annual property tax expense for CRNF by an average of approximately $11.7 million per year for the year ended December 31, 2010, and approximately $10.7 million for the years ended December 31, 2009 and 2008, respectively. CRNF does not agree with the county’s classification of the nitrogen fertilizer plant and CRNF is currently disputing it before the Kansas Court of Tax Appeals (“COTA”). However, CRNF has fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008 and has estimated and accrued for property taxes for the first six months of 2011. These amounts are reflected as a direct operating expense in the Condensed Consolidated Statements of Operations. An evidentiary hearing before COTA occurred during the first quarter of 2011 regarding the property tax claims for the year ended December 31, 2008. CRNF believes it is possible that COTA may issue a ruling sometime during 2011. However, the timing of a ruling in the case is uncertain, and there can be no assurance CRNF will receive a ruling in 2011. If CRNF is successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, a portion of the accrued and paid expenses would be refunded to CRNF, which could have a material positive effect on CRNF’s and the Company’s results of operations. If CRNF is not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, CRNF expects that it will continue to pay property taxes at elevated rates.

 

On July 25, 2011, Mid-America Pipeline Company, LLC (“MAPL”) filed an application with the Kansas Corporation Commission (“KCC”) for the purpose of establishing rates (“New Rates”) effective October 1, 2011 for pipeline transportation service on MAPL’s liquids pipelines running between Conway, Kansas and Coffeyville, Kansas (“Inbound Line”) and between Coffeyville, Kansas and El Dorado, Kansas (“Outbound Line”). CRRM currently ships refined fuels on the Outbound Line pursuant to transportation rates established by a pipeline capacity lease with MAPL which expires September 30, 2011 and CRRM currently ships natural gas liquids on the Inbound Line pursuant to a pipeage contract which also expires September 30, 2011. Although CRRM intends to vigorously contest the New Rates at the KCC, if MAPL is successful in obtaining

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the entirety of its proposed rate increase, under CRRM’s historic pipeline usage patterns, the New Rates would result in a total annual increase of approximately $14.75 million for CRRM’s use of the Inbound and the Outbound Lines.

 

See note (1) to the table at the beginning of this Note 11 (“Commitments and Contingencies”) 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 the 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 $4.4 million (plus punitive damages). In August 2008, those claimants filed suit against the Company in the United States District Court for the District of Kansas in Wichita (the “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 $3.2 million (plus punitive damages) for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge. In August 2010, the Company settled claims with eight of the plaintiffs from the Angleton Case, and in May and June 2011, the Company settled six more claims in the Angleton and companion case. The settlements did not have a material adverse effect on the consolidated financial statements. The Company believes that the resolution of the remaining 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 United States Environmental Protection Agency (“EPA”) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of crude oil from the Company’s refinery caused an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company’s refinery. The substantial majority of all required remedial actions were completed by January 31, 2009. The Company prepared and provided its final report to the EPA in January 2011 to satisfy the final requirement of the Consent Order. In April 2011, the EPA provided the Company with a notice of completion indicating that the Company has no continuing obligations under the Consent Order, while reserving its rights to recover oversight costs and penalties.

 

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. On October 25, 2010, the Company received a letter from the United States Coast Guard on behalf of the EPA claiming approximately $1.8 million in oversight cost reimbursement. The Company has responded by asserting defenses to the Coast Guard’s claim for oversight costs. The EPA has indicated that it intends to seek to recover a civil penalty related to the oil spill, but no demand has been made. The Company intends to assert the same defenses to liability for any civil penalty that may be made.

 

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and third-party property damage claims. On July 10, 2008, the Company filed a lawsuit in the United States District Court for the District of Kansas against certain of the Company’s environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. Although the Court has now issued summary judgment opinions that eliminate the majority of the insurance defendants’ reservations and defenses, 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 $25.0 million of insurance proceeds under its primary

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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.

 

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.

 

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). As of June 30, 2011 and December 31, 2010, environmental accruals of $2.6 million and $4.1 million, respectively, were reflected in the Condensed Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.9 million and approximately $1.5 million, respectively, are included in other current liabilities. The Company’s accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at June 30, 2011 and December 31, 2010, respectively. The accruals include estimated closure and post-closure costs of $0.9 million and approximately $0.9 million for two landfills at June 30, 2011 and December 31, 2010, respectively. The estimated future payments for these required obligations are as follows:

 

 

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.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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. Capital expenditures to comply with the rule are expected to be approximately $10.0 million.

 

CRRM is subject to the Renewable Fuel Standard (“RFS”) which requires refiners to blend “renewable fuels” in with their transportation fuels or purchase renewable energy credits in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the previous year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. Thus, in 2011, about 8% of all fuel used will be “renewable fuel.” In 2012, the EPA has proposed to raise the renewable fuel percentage standards to about 9%. Due to mandates in the RFS 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 to the extent that these increased costs cannot be passed on to the consumers. CRRM’s small refiner status under the original RFS expired on December 31, 2010. Beginning on January 1, 2011, CRRM was required to blend renewable fuels into its gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (RINs) in lieu of blending. For the three and six months ended June 30, 2011, CRRM incurred approximately $5.0 million and $8.5 million, respectively, of expense associated with the required mandate which was included in cost of product sold in the Condensed Consolidated Statements of Operations. To achieve compliance with the renewable fuel standard for the remainder of 2011, CRRM will blend renewable fuels into its refined products whenever possible and will also purchase RINs to bridge any shortfall created by a deficiency in renewable fuel blended production.

 

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 crude oil refinery and Phillipsburg terminal facilities. As a result of CRRM’s 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 remaining costs of complying with the Consent Decree are expected to be approximately $49.0 million, of which approximately $47.0 million is expected to be capital expenditures which does not include the cleanup obligations for historic contamination at the site that are being addressed pursuant to administrative orders issued under 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 fifteen 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 agreed to offset any incremental emissions resulting from the delay by providing additional controls to existing emission sources over a set timeframe.

 

In the meantime, CRRM has been negotiating with the EPA and KDHE to replace the current Consent Decree, including the fifteen month extension, with a global settlement under the National Petroleum Refining Initiative. Over the course of the last decade, the EPA has embarked on a 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 Refining Initiative has resulted in most refineries entering into consent decrees imposing civil penalties and requiring substantial expenditures for pollution control and enhanced operating procedures. The EPA has

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

indicated that it will seek to have all refiners enter into “global settlements” pertaining to all “marquee” issues. The current Consent Decree covers some, but not all, of the “marquee” issues. The Company has been negotiating with the EPA to expand the existing Consent Decree obligations to include all of the “marquee” issues under the Petroleum Refining Initiative, and the parties have reached an agreement in principle on most of the issues, including an agreement to further extend the deadline for the installation of controls on the FCCU. Under the global settlement, the Company may be required to pay a civil penalty, but the incremental capital expenditures would not be material and would be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe.

 

On February 24, 2010, the Company received a letter from the United States Department of Justice on behalf of the EPA seeking an approximately $0.9 million civil penalty related to alleged late and incomplete reporting of air releases in violation of the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and the Emergency Planning and Community Right-to-Know Act (“EPCRA”). The Company has reviewed and is contesting the EPA’s allegation. CRRM has entered into a tolling agreement concerning EPA’s claims. The tolling agreement in 2010 was amended to include the EPA’s allegations related to CRRM’s compliance with the Clean Air Act’s Risk Management Program (“RMP”). EPA has investigated CRRM’s operation for compliance with the RMP program, but has not made any claims against CRRM.

 

From time to time, the EPA has conducted inspections and issued information requests to CRNF with respect to the Company’s compliance with the RMP and the release reporting requirements under CERCLA and the EPCRA. These previous investigations have resulted in the issuance of preliminary findings regarding CRNF’s compliance status. In the fourth quarter of 2010, following CRNF’s reported release of ammonia from its cooling water system and the rupture of its UAN vessel (which released ammonia and other regulated substances), the EPA conducted its most recent inspection and issued an additional request for information to CRNF. The EPA has not made any formal claims against the Company and the Company has not accrued for any liability associated with the investigations or releases.

 

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended June 30, 2011 and 2010, capital expenditures were approximately $0.9 million and $3.3 million, respectively. For the six months ended June 30, 2011 and 2010, capital expenditures were approximately $2.5 million and $11.0 million, respectively. These expenditures were incurred to improve the environmental compliance and efficiency of the 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.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

Long-term debt was as follows:

 

 

Senior Secured Notes

 

On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance Inc. (together the “Issuers”), completed a private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. The associated original issue discount of the Notes is amortized to interest expense and other financing costs over the respective term of the Notes. On December 30, 2010, CRLLC made a voluntary unscheduled principal payment of $27.5 million on the First Lien Notes that resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount. On May 16, 2011, CRLLC repurchased $2.7 million of the Notes at a purchase price of 103% of the outstanding principal amount, which resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized issue discount. At June 30, 2011, the estimated fair value of the First and Second Lien Notes was approximately $266.0 million and $250.0 million, 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, with the exception of the Partnership and CRNF. In connection with the closing of the Partnership’s initial public offering in April 2011, the Partnership and CRNF were released from their guarantees of the 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.

 

Senior Notes Tender Offer

 

The completion of the initial public offering of the Partnership in April 2011 triggered a Fertilizer Business Event (as defined in the indentures governing the Notes). As a result, CRLLC and Coffeyville Finance Inc. were required to offer to purchase a portion of the Notes from holders at a purchase price equal to 103.0% of the principal amount plus accrued and unpaid interest. A Fertilizer Business Event Offer was made on April 14, 2011 to purchase up to $100.0 million of the First Lien Notes and the Second Lien Notes, as required by the indentures governing the Notes. Holders of the Notes had until May 16, 2011 to properly tender Notes they wished to have repurchased. Approximately $2.7 million of the Notes were repurchased, including approximately $0.5 million of First Lien Notes and $2.2 million of Second Lien Notes.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

ABL Credit Facility

 

On February 22, 2011, CRLLC and certain other subsidiaries of CVR entered into a $250.0 million asset-backed revolving credit agreement (“ABL credit facility”) with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. The ABL credit facility, which is scheduled to mature in August 2015, replaced the $150.0 million first priority revolving credit facility which was terminated. The ABL credit facility will be used to finance ongoing working capital, capital expenditures, letter of credit issuances and general needs of the Company and includes, among other things, a letter of credit sublimit equal to 90% of the total facility commitment and an accordion feature which permits an increase in borrowings of up to $250.0 million (in the aggregate), subject to receipt of additional lender commitments. As of June 30, 2011, CRLLC had availability under the ABL credit facility of $218.4 million and had letters of credit outstanding of approximately $31.6 million. There were no borrowings outstanding under the ABL credit facility as of June 30, 2011.

 

Borrowings under the facility bear interest based on a pricing grid determined by the previous quarter’s excess availability. The pricing for LIBOR loans under the ABL credit facility can range from LIBOR plus 2.75% to LIBOR plus 3.0%, for base rate loans, the prime rate plus 1.75% to prime rate plus 2.0%. Availability under the ABL credit facility is determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory.

 

The ABL credit facility contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness, the creation of liens on assets, the ability to dispose of assets, the ability to make restricted payments, investments or acquisitions, sale-leaseback transactions and affiliate transactions. The ABL credit facility also contains a fixed charge coverage ratio financial covenant that is triggered when borrowing base excess availability is less than certain thresholds, as defined under the facility. As of June 30, 2011, CRLLC was in compliance with the covenants of the ABL credit facility.

 

In connection with the ABL credit facility, through June 30, 2011, CRLLC has incurred lender and other third party costs of approximately $5.9 million. These costs were deferred and are being amortized to interest expense and other financing costs using a straight-line method over the term of the facility. In connection with termination of the first priority credit facility, a portion of the unamortized deferred financing costs associated with the facility, totaling approximately $1.9 million, was written off in the first quarter of 2011. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $0.8 million of unamortized deferred financing costs associated with the first priority credit facility will continue to be amortized over the term of the ABL credit facility.

 

Included in other current liabilities on the Condensed Consolidated Balance Sheets is accrued interest payable totaling approximately $12.9 million and $12.2 million as of June 30, 2011 and December 31, 2010, respectively. As of June 30, 2011, of the accrued interest payable, approximately $11.6 million is related to the Notes. As of December 31, 2010, of the accrued interest payable, approximately $11.8 million is related to the Notes and the first priority credit facility borrowing arrangement.

 

In connection with the closing of the Partnership’s initial public offering in April 2011, the Partnership and CRNF were released as guarantors of the ABL credit facility.

 

CRNF Credit Facility

 

On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. No amounts were outstanding under the revolving credit facility at June 30, 2011. There is no scheduled amortization of the credit facility with it being due and payable in full at its April 2016 maturity. The Partnership, upon the

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

closing of the credit facility, made a special distribution of approximately $87.2 million to CRLLC, in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation of the Offering. The credit facility will be used to finance on-going working capital, capital expenditures, letters of credit issuances and general needs of CRNF.

 

Borrowings under the credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the credit facility is the Eurodollar rate plus a margin of 3.75% or, for base rate loans, the prime rate plus 2.75%. Under its terms, the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Partnership.

 

The credit facility requires CRNF to maintain a minimum interest coverage ratio and a maximum leverage ratio and contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make restricted payments, investments and acquisitions, sale-leaseback transactions and affiliate transactions. The credit facility provides that the Partnership can make distributions to holders of its common units provided, among other things, it is in compliance with the leverage ratio and interest coverage ratio on a pro forma basis after giving effect to any distribution and there is no default or event of default under the credit facility. As of June 30, 2011, CRNF was in compliance with the covenants of the credit facility.

 

In connection with the credit facility, through June 30, 2011, CRNF has incurred lender and other third party costs of approximately $4.9 million. The costs associated with the credit facility have been deferred and are being amortized over the term of the credit facility as interest expense using the effective-interest amortization method for the term loan facility and the straight-line method for the revolving credit facility.

 

 

In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures (“ASC 820”), the Company utilizes the market approach to measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

 

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:

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of June 30, 2011 and December 31, 2010:

 

 

 

As of June 30, 2011, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company’s money market accounts, available-for-sale marketable securities and derivative instruments. Additionally, the fair value of the Company’s Notes is disclosed in Note 12 (“Long-Term Debt”). 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, 2011.

 

The Company’s investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair market value using quoted market prices. These marketable securities totaled approximately $25,000 as of June 30, 2011 and are included in other current assets on the Condensed Consolidated Balance Sheet. Unrealized gains or losses, net of related income tax are reported as a component of accumulated other comprehensive income. For the six months ended June 30, 2011, the unrealized gain, net of tax, associated with these marketable securities was nominal.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

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

 

 

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 from time to time enters into various commodity derivative transactions. The Company, as further described below, entered into an interest rate swap as required by its long-term debt agreements. The interest rate swap was for the purpose of managing interest rate risk until June 30, 2010.

 

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.

 

CVR maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include funds available for withdrawal. These funds are included in cash and cash equivalents within the Condensed Consolidated Balance Sheets. The maintenance margin balance is included within other current assets within the Condensed Consolidated Balance Sheets. Dependant upon the position of the open commodity derivatives, the amounts are accounted for as an other current asset or an other current liability within the Condensed Consolidated Balance Sheets. From time to time, CVR may be required to deposit additional funds into this margin account.

 

Interest Rate Swap — CRLLC

 

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 $180.0 million from March 31, 2009 until March 31, 2010 and approximately $110.0 million from March 31, 2010 until June 30, 2010. The Interest Rate Swap expired on June 30, 2010. Half of the Interest 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 were 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.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Interest Rate Swap — CRNF

 

On June 30 and July 1, 2011, CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of its $125 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements totals $62.5 million (split evenly between the two agreement dates) and commences on August 12, 2011 and expires on February 12, 2016. Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three-month LIBOR as governed by the CRNF credit agreement. If the swaps were in effect at June 30, 2011, the effective rate would be approximately 5.71% based on the current applicable margin of 3.75% over three-month LIBOR. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap will be initially reported as a component of accumulated other comprehensive income (loss) (“AOCI”), and subsequently reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense.

 

 

Until February 2011, the Goldman Sachs Funds and Kelso Funds owned approximately 40% of CVR. On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold into the public market its remaining ownership interest in CVR and Kelso substantially reduced its interest in the Company. On May 26, 2011, Kelso completed a registered public offering in which Kelso sold into the market its remaining ownership interest in CVR. As a result of these sales, the Goldman Sachs Funds and Kelso Funds are no longer stockholders of the Company.

 

Interest Rate Swap

 

On June 30, 2005, the Company entered into three Interest Rate Swap agreements with J. Aron. These swap agreements expired on June 30, 2010. As such, there was no financial statement impact for the three and six months ended June 30, 2011. Net losses totaling $0 and $0 were recognized related to these swap agreements for the three months ended June 30, 2011 and 2010, respectively, and were reflected in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. Net losses totaling $0 and $16,000 were recognized related to these swap agreements for the six months ended June 30, 2011 and 2010, respectively, and were reflected in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. See Note 14 (“Derivative Financial Instruments”) for additional information.

 

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, 2011 and December 31, 2010, the balance in the account was approximately $161.1 million and $70.1 million, respectively. For the three months ended June 30, 2011 and 2010, the account earned interest income of approximately $4,000 and $2,000, respectively. For the six months ended June 30, 2011 and 2010, the account earned interest income of approximately $9,000 and $2,000, 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 approximately $0.9 million for its services as lead bookrunner.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

For the three and six months ended June 30, 2011, the Company recognized approximately $0.3 and $0.5 million, 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.

 

In connection with the Offering of the Partnership, an affiliate of GS received an underwriting fee of approximately $5.7 million for its role as a joint book-running manager. In April 2011, CRNF entered into a credit facility as discussed further in Note 12 (“Long-Term Debt”) whereby an affiliate of GS was paid fees and expenses of approximately $2.0 million.

 

 

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 Topic 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 in accordance with a pet coke supply agreement. 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 price the Nitrogen Fertilizer Segment pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in Petroleum Segment net sales were approximately $3.5 million and $1.8 million for the three months ended June 30, 2011 and 2010, respectively. Intercompany sales included in Petroleum Segment net sales were approximately $4.9 million and $2.2 million for the six months ended June 30, 2011 and 2010, respectively.

 

The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases (sales) described below under “Nitrogen Fertilizer” for the three months ended June 30, 2011 and 2010 of approximately $6.1 million and $(0.6 million), respectively. For the six months ended June 30, 2011 and 2010, the Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases (sales) of approximately $5.3 million and $(1.1 million), respectively.

 

Nitrogen Fertilizer

 

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $2.9 million and $0.6 million for the three months ended June 30, 2011 and 2010, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $3.6 million and $1.0 million for the six months ended June 30, 2011 and 2010, 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

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 $0 and approximately $0.7 million for the three and six months ended June 30, 2011, respectively. For the three and six months ended June 30, 2011, the Nitrogen Fertilizer Segment recorded net sales generated from intercompany sales of hydrogen to the Petroleum Segment of approximately $6.1 million. For the three and six months ended June 30, 2010, the Nitrogen Fertilizer Segment recorded costs of product sold (exclusive of depreciation and amortization) from intercompany hydrogen purchases of approximately $0.6 million and $1.1 million, respectively.

 

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.