CVR ENERGY INC - Quarter Report: 2011 March (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)

 

 

(Registrant’s telephone number, including area code)

(281) 207-3200

 

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

 

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

 

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

(Do not check if a smaller reporting company)

 

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

 

There were 86,413,781 shares of the registrant’s common stock outstanding at May 6, 2011.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended March 31, 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.

 

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

 

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

 

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.

 

 

CVR Energy, Inc. and Subsidiaries

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

See accompanying notes to the condensed consolidated financial statements.

CVR Energy, Inc. and Subsidiaries

 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

See accompanying notes to the condensed consolidated financial statements.

CVR Energy, Inc. and Subsidiaries

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

See accompanying notes to the condensed consolidated financial statements.

CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 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 majority-owned subsidiaries, acts as an independent producer and marketer of upgraded nitrogen fertilizer products in North America. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.

 

CVR is subject to the rules and regulations of the New York Stock Exchange where its shares are traded 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 Energy. Additionally, Kelso reduced its interests in the Company and as of the date of this Report beneficially owns approximately 9% of all shares outstanding.

 

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 $10,600,000. This interest has been classified as a noncontrolling interest included as a separate component of equity in the Condensed Consolidated Balance Sheets at March 31, 2011 and 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, our subsidiary (“CRLLC”). The payment for the IDRs was paid to 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 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 net income and distributions of the Partnership.

 

As of March 31, 2011 and until the completion of the Offering by the Partnership, CVR owned all of the interests in the Partnership (other than the managing GP interest and the IDRs) and was entitled to all cash distributed by the Partnership, except with respect to IDRs. At March 31, 2011, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interest outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

managing general partner owned the managing GP interest and the IDRs. The managing general partner contributed 1% of CRNF’s interest to the Partnership in exchange for its managing GP interest and the IDRs.

 

In addition, as of March 31, 2011, the Partnership and its subsidiary were guarantors under CRLLC’s asset backed revolving credit facility (“ABL credit facility”) and senior secured notes. In connection with the Offering, the Partnership was subsequently released from its obligations as a guarantor under the ABL credit facility and senior secured notes, as described further in Note 12 (“Long-Term Debt”).

 

On April 13, 2011, the Partnership completed its initial public offering of 22,080,000 common units priced at $16.00 per unit (such amount includes commitments issued pursuant to the exercise of the underwriters’ over-allotment option). The common units, which are listed on the New York Stock Exchange, began trading on April 7, 2011 under the symbol “UAN”.

 

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 $353,280,000 prior to underwriting discount and other offering costs. In connection with the Offering, the Partnership paid approximately $24,730,000 in underwriting fees and incurred approximately $4,000,000 of other offering costs. Approximately $5,741,000 of the underwriter fee was paid to an affiliate of GS acting as joint book-running managers. Until completion of the 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 with its non-economic general partner 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, 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:

 

 

Following the Offering, the Partnership will make quarterly cash distributions to unitholders. The partnership agreement does not require that the Partnership make cash distributions on a quarterly or other

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 pursuant to an amended and restated services agreement, effective April 13, 2011, 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 general partner is owned by CRLLC, a wholly-owned subsidiary of CVR. 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 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. 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

 

In accordance with Accounting Standards Codification (“ASC”) Topic 810-10 — Consolidations-Variable Interest Entities, (“ASC 810-10”), as of March 31, 2011, management has determined that the Partnership is a variable interest entity (“VIE”) and as such evaluated the qualitative criteria under ASC 810-10 to make this determination. 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.

 

The conclusion that CVR is the primary beneficiary of the Partnership and is required to consolidate the Partnership as a VIE is based primarily on the fact that the general partner’s officers manage the day-to-day operations and activities of the Partnership. These officers of the general partner are also officers of CVR Energy. As such, they have the power to direct the activities of the Partnership that most significantly impacts the entity’s economic performance.

 

As a result of the Offering, the basis of consolidation of the Partnership into CVR Energy is based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR Energy; and, therefore has the ability to control the activities of the Partnership. Additionally, 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 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. 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 Energy will include the assets, liabilities, cash flows, revenues and expenses of the Partnership.

 

The limited rights of the limited partners are demonstrated by the fact that the limited partners 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 Energy) voting together as a single class. Upon completion of the Offering,

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

the general partner and its affiliates, through CRLLC, own an aggregate of approximately 69.8% of the outstanding common units. This gives CRLLC the ability to prevent removal of the general partner.

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). The 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 March 31, 2011 and December 31, 2010, the results of operations and cash flows for the three months ended March 31, 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 July 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-20, which amends ASC Topic 310, “Receivables” to provide greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables. This ASU will require an entity to disclose (1) the inherent credit risk in its financing receivables, (2) how the credit risk is analyzed and assessed in calculating the allowance for credit losses and (3) the changes and reasons for those changes in the allowance for credit losses. The provisions of ASU No. 2010-20 are effective for interim and annual reporting periods ending on or after December 31, 2010. The adoption of this standard did not impact the Company’s financial position or results of operations.

 

In January 2010, the FASB issued ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” an amendment to ASC Topic 820, “Fair Value Measurements and Disclosures.” This amendment requires an entity to: (i) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, (ii) present separate information for Level 3 activity pertaining to gross purchases, sales, issuances, and settlements and (iii) enhance disclosures of assets and liabilities subject to fair value measurements. The provisions of ASU No. 2010-06 are effective for the Company for interim and annual reporting beginning after December 15, 2009, with one new disclosure effective after December 15, 2010. The Company adopted this ASU as of

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

January 1, 2010. The adoption of this standard did not impact the Company’s financial position or results of operations.

 

 

Prior to CVR’s initial public offering in October 2007, CVR’s subsidiaries were held and operated by Coffeyville Acquisition LLC (“CALLC”) and its subsidiaries. Management of CVR holds an equity interest in CALLC. CALLC issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with CVR’s initial public offering 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.

 

For the three months ended March 31, 2011, the estimated fair value of the CALLC III override units were determined using a probability-weighted expected return method which utilized CALLC III’s cash flow projections and also considered the proposed initial public offering of the Partnership, including the purchase of the IDRs and the managing GP interest. For the three months ended March 31, 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.

 

At March 31, 2011, the estimated fair value of the override units of CALLC was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of the Company’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are vested. The 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 months ended March 31, 2010.

 

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 as of the date of this Report and CALLC II is no longer a stockholder of the Company. Subsequent to

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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.

 

The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC III.

 

 

 

 

Valuation Assumptions

 

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

 

 

On the tenth anniversary of the issuance of override operating units, such units convert into an equivalent number of override value units. Override operating units are forfeited upon termination of employment for cause. As of March 31, 2011, these units were fully vested.

 

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

 

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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

 

 

(e) Override Units — Using a binomial and a probability-weighted expected return method 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 has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. As of March 31, 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 has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. Of the 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units are subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows:

 

 

Based upon the estimated fair value at March 31, 2011, there was approximately $818,000 of unrecognized compensation expense related to non-voting override units. This expense is expected to be recognized over a remaining period of less than one year. To the extent the price of CVR’s common stock increases additional share-based compensation expense will be incurred with respect to unvested override units.

 

Phantom Unit Appreciation Plan

 

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. As of March 31, 2011, the issued Profits Interest (combined phantom points and override units) represented 15.0% of combined common unit interest and Profits Interest of CALLC and CALLC II. The Profits Interest was

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

comprised of approximately 11.1% of override interest and approximately 3.9% of phantom interest. The expense associated with these awards is based on the current fair value of the awards which was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible 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 $9,849,000 and $18,689,000 in personnel accruals as of March 31, 2011 and December 31, 2010, respectively. Compensation expense for the three months ended March 31, 2011 and 2010 related to the Phantom Unit Plans was $11,240,000 and $3,399,000, respectively. Using the Company’s closing stock price at March 31, 2011 and 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:

 

 

As described above, in February 2011, CALLC and CALLC II 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 $20,079,000 in the first quarter of 2011.

 

Based upon the estimated fair value at March 31, 2011, there was approximately $107,000 of unrecognized compensation expense related to the Phantom Unit Plans. This is expected to be recognized over a remaining period of less than one year. To the extent the price of CVR’s common stock increases, additional share-based compensation expense will be incurred with respect to the remaining phantom unit awards.

 

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 March 31, 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 March 31, 2011, there have been a total of 32,350 stock options granted, of which 24,718 have vested. However, 6,301 vested options have expired resulting in a net total of 18,417 outstanding options that have vested. Additionally, 3,149 unvested stock options were forfeited in the second quarter of 2010. There were no options vested, forfeited or granted in the first 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 March 31, 2011, there was approximately $5,000 of total unrecognized compensation cost related to stock options to be recognized over a weighted-average period of less than one year.

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Restricted Stock

 

A summary of restricted stock grant activity and changes during the three months ended March 31, 2011 is presented below:

 

 

Through the LTIP, shares of non-vested restricted stock have been granted to employees of the Company. Non-vested 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 March 31, 2011, there was approximately $11,180,000 of total unrecognized compensation cost related to non-vested restricted shares to be recognized over a weighted-average period of approximately two years.

 

Compensation expense recorded for the three months ended March 31, 2011 and 2010 related to the non-vested restricted stock and stock options was $2,224,000 and $173,000, respectively.

 

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. In connection with the Offering, phantom units were issued to certain board members of the general partner. These phantom units are expected to vest six months following the grant date.

 

 

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 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.

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 March 31, 2011 and 2010, totaled approximately $86,000 and $881,000, respectively. Buildings and equipment that are under a capital lease obligation approximated $332,000 as of March 31, 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 $632,000 and $728,000 for the three months ended March 31, 2011 and 2010, 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 $20,876,000 and $20,018,000 for the three months ended March 31, 2011 and 2010, respectively.

 

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, 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

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

administrative expenses exclude depreciation and amortization of $503,000 and $514,000 for the three months ended March 31, 2011 and 2010, 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 $5,000,000. The Company began to repay this note in equal installments commencing October 1, 2010. As of March 31, 2011 and December 31, 2010, the Company owed $1,250,000 and $3,125,000, 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 $415,000. The two capital leases entered into during 2010 have terms of 12 and 36 months. As of March 31, 2011, the outstanding capital lease obligation associated with these leases totaled $245,000.

 

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 total $80,000 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 $4,587,000 as of December 31, 2010. In March 2011, the Company exercised its purchase option and paid approximately $4,739,000 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 March 31, 2011 due to the incident was approximately $10,893,000 for repairs and maintenance and other associated costs. Approximately $371,000 of these costs was recognized during the three months ended March 31, 2011. The repairs and maintenance costs incurred are included in direct operating expenses (exclusive of depreciation and amortization). Of the costs incurred approximately $4,445,000 was capitalized.

 

The Company maintains property damage insurance policies which have an associated deductible of $2,500,000. The Company anticipates that substantially all of the repair costs in excess of the $2,500,000 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 $4,500,000, of which $4,275,000 of insurance proceeds was received in December 2010 and the remaining $225,000 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

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

payments totaling $2,870,000. Through March 31, 2011, the Company had received insurance proceeds totaling $2,315,000 related to its business interruption claim and received the remaining $555,000 in April 2011. The proceeds received and to be received as of March 31, 2011 have been included on the Condensed Consolidated Statements of Operations under Insurance recovery -business interruption.

 

Refinery Incident

 

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 March 31, 2011 was approximately $8,005,000. Of this amount approximately $7,390,000, was recorded during the three months ended March 31, 2011. As documented above, the Company maintains property damage insurance policies which have an associated deductible of $2,500,000. The Company anticipates that substantially all of the costs in excess of the deductible should be covered by insurance. As of March 31, 2011, the Company recorded an insurance receivable related to the incident of approximately $5,505,000. 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. As of March 31, 2011, the Company had unrecognized tax benefits of approximately $245,000 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 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 March 31, 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 months ended March 31, 2011 was 37.2%, 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 months ended March 31, 2010 was 38.4%.

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

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

 

 

Outstanding stock options totaling 19,606 and 32,350 common shares were excluded from the diluted earnings per share calculation for the three months ended March 31, 2011 and 2010, respectively, as they were antidilutive. For the three months ended March 31, 2010, 176,727 shares of non-vested common stock were excluded from the diluted earnings (loss) per share calculation, as they were antidilutive.

 

 

Leases and Unconditional Purchase Obligations

 

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

 

 

 

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

The Company leases various equipment, including rail cars, and real properties under long-term operating leases, expiring at various dates. For the three months ended March 31, 2011 and 2010, lease expense totaled $1,275,000 and $1,192,000, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at the Company’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire. The Company also has other customary operating leases and unconditional purchase obligations primarily related to pipeline, 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.

 

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 remain 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 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

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008 The first payment in respect of CRNF’s 2010 property taxes was paid in December 2010 and the second payment was paid in May 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 COTA is likely to 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 the 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 pay taxes at or below the elevated rates described above.

 

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 $4,393,000 (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 $3,200,000 (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. 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 condensed 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 U.S. 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 requested detailed cost data in order to evaluate the claim. The Company has reviewed and is in the process of responding to the cost data.

 

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and property damage claims. On July 10, 2008, the Company filed a lawsuit in the United States District Court for the District of Kansas against certain of the Company’s environmental and property insurance

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 $25,000,000 of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment to the Company of the primary pollution liability policy limit.

 

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

 

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). In 2005, CRNF agreed to participate in the State of Kansas Voluntary Cleanup and Property Redevelopment Program (“VCPRP”) to address a reported release of UAN at its UAN loading rack. As of March 31, 2011 and December 31, 2010, environmental accruals of $3,273,000 and $4,090,000, respectively, were reflected in the Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders and the VCPRP, for which $929,000 and $1,538,000, 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 March 31, 2011 and December 31, 2010, respectively. The accruals include estimated closure

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

and post-closure costs of $887,000 and $921,000 for two landfills at Mach 31, 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.

 

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.

 

In November 2010, the EPA finalized changes to the Renewable Fuel Standards (“RFS”) which require the total volume of renewable transportation fuels sold or introduced in the U.S. to reach 13.95 billion gallons in 2011 and rise to 36 billion gallons by 2022. 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 months ended March 31, 2011, CRRM incurred $3.5 million of expense associated with the required mandate which was included in cost of product sold in the Condensed Consolidated Statements of Operations. CRRM will utilize a combination of blending and purchase of additional RINS in 2011 in order to achieve compliance with the renewable fuel standard for the remainder of 2011.

 

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 million, of which approximately $47 million is expected to be capital expenditures which does not

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 National Petroleum Refining Initiative alleging industry-wide noncompliance with four “marquee” issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The Petroleum 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 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 a $900,000 civil penalty related to alleged late and incomplete reporting of air releases in violation of the Comprehensive Environmental Response, Compensation, and Liability Act and the Emergency Planning and Community Right to Know Act. The Company has reviewed and intends to contest the EPA’s allegation.

 

In 2007, the federal Occupational Safety and Health Act (“OSHA”) began process safety management (“PSM”) inspections of all refineries under its jurisdiction as part of its National Emphasis Program (the “NEP”). In addition, OSHA announced in 2009 that it was going to pursue NEP inspections for chemical operations. As such, OSHA began a PSM NEP inspection at the nitrogen fertilizer plant in late 2010 resulting in an assessed penalty of approximately $9,700 and noted no serious violations.

 

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended March 31, 2011 and 2010, capital expenditures were approximately $1,578,000 and $7,663,000, respectively, and 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.

CVR Energy, Inc. and Subsidiaries

 

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 $275,000,000 aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225,000,000 aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with 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 $27,500,000 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. At March 31, 2011, the estimated fair value of the First and Second Lien Notes was $269,156,000 and $255,938,000, respectively. These estimates of fair value were determined by quotations obtained from a broker-dealer who makes a market in these and similar securities. The Notes are fully and unconditionally guaranteed by each of CRLLC’s subsidiaries that also guarantee the first priority credit facility. 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 in the indentures governing the Notes. Holders of the Notes have until May 16, 2011 to properly tender Notes they wish to have repurchased.

 

ABL Credit Facility

 

On February 22, 2011, CRLLC 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 is scheduled to mature in August 2015 and

CVR Energy, Inc. and Subsidiaries

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 a feature which permits an increase in borrowings of up to $500.0 million (in the aggregate), subject to additional lender commitments. As of March 31, 2011, CRLLC had availability under the ABL credit facility of $208,356,000 and had letters of credit outstanding of approximately $41,644,000. There were no borrowings outstanding from the ABL credit facility as of March 31, 2011.

 

Borrowings under the facility bear interest based on a pricing grid determined by the previous quarter’s excess availability. The pricing for borrowings under the ABL credit facility can range from LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to prime rate plus 2.0% for Base Rate Loans. 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, creation of liens on assets, the ability to dispose of assets, make restricted payments, investments or acquisitions, enter into sale-lease back transactions or enter into 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 March 31, 2011, CRLLC was in compliance with the covenants of the ABL credit facility.

 

In connection with the ABL credit facility, through March 31, 2011, CRLLC has incurred lender and other third party costs of approximately $4,996,000. These costs will be deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the facility. Additionally, in connection with termination of the first priority credit facility, a portion of the unamortized deferred financing costs associated with this facility, totaling approximately $1,908,000, 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 $781,000 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 $23,780,000 and $12,167,000 as of March 31, 2011 and December 31, 2010, respectively. As of March 31, 2011, of the accrued interest payable, approximately $23,372,000 is related to the Notes. As of December 31, 2010, of the accrued interest payable, approximately $11,837,000 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.

 

See Note 17 (“Subsequent Events”) for discussion of the $125.0 million credit facility entered into in April 2011 by CRNF to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF.

 

 

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.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:

 

 

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

 

 

 

As of March 31, 2011, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company’s money market account, 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 three months ended March 31, 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 $27,000 as of March 31, 2011 and are included in other current assets on the Condensed Consolidated Balance Sheets. Unrealized gains or losses, net of related income taxes are reported as a component of accumulated other comprehensive income. For the three months ended March 31, 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.

 

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

 

Until June 30, 2010, CRLLC held derivative contracts known as interest rate swap agreements (the “Interest Rate Swap”) that converted CRLLC’s floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of $180,000,000 from March 31, 2009 until March 31, 2010 and $110,000,000 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)

 

 

Until February 2011, the Goldman Sachs Funds and Kelso Funds owned approximately 40% of CVR. Through a registered public offering, the Goldman Sachs Funds and the Kelso Funds sold into the public market shares of CVR Energy common stock in February 2011. As a result of this sale, the Goldman Sachs Funds are no longer a stockholder of the Company and, as of the date of this Report, the Kelso Funds’ own approximately 9% of CVR’s common stock.

 

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 months ended March 31, 2011. Net losses totaling $15,000 were recognized related to these swap agreements for the three months ended March 31, 2010 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 March 31, 2011 and December 31, 2010, the balance in the account was approximately $11,057,000 and $70,052,000, respectively. For the three months ended March 31, 2011, the account earned interest income of approximately $5,000. The interest income earned on the account for the three months ended March 31, 2010 was nominal.

 

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 $905,000 for their services as lead bookrunner.

 

For the three months ended March 31, 2011 and 2010, the Company recognized approximately $265,000 and $21,000, respectively, in expenses for the benefit of GS and Kelso in accordance with CVR’s Registration Rights Agreement. These amounts included registration and filing fees, printing fees, external accounting fees and external legal fees.

 

In connection with the Offering of the Partnership, an affiliate of GS received an underwriting fee of $5,741,000 for their role as joint book-running managers. In April 2011, CRNF entered into a credit facility as discussed further in Note 17 (“Subsequent Events”) whereby an affiliate of GS was paid fees and expenses of $2,004,000.

 

 

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

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 net sales were $1,372,000 and $413,000 for the three months ended March 31, 2011 and 2010, respectively.

 

The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under “Nitrogen Fertilizer” for the three months ended March 31, 2011 and 2010 of $719,000 and $568,000, respectively.

 

Nitrogen Fertilizer

 

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was $750,000 and $438,000 for the three months ended March 31, 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 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 $719,000 and $568,000 for the three months ended March 31, 2011 and 2010, respectively. For the three months ended March 31, 2011 and 2010, there were no net sales of hydrogen from the Nitrogen Fertilizer Segment to the Petroleum Segment.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Other Segment

 

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

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

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 $125,000,000 and a revolving credit facility of $25,000,000 with an uncommitted incremental facility of up to $50,000,000. 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 closing of the credit facility, made a special distribution of approximately $87,192,000 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, letter 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 borrowings under the credit facility will be the Eurodollar rate plus a margin of 3.75% or the prime rate plus 2.75% for base rate loans. 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 contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, creation of liens on assets, the ability to dispose of assets make restricted payments, investments or acquisitions, enter into sale-lease back transactions or enter into affiliate transactions. The credit facility provides that the Partnership can make distributions to holders of its common units provided it is in compliance with the Partnership’s leverage ratio and interest coverage ratio covenants on a pro forma basis after giving effect to any distribution and there is no default or event of default under the credit facility.

 

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes and with the statistical information and financial data appearing in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, as well as our Annual Report on Form 10-K for the year ended December 31, 2010. Results of operations for the three months ended March 31, 2011 are not necessarily indicative of results to be attained for any other period.

 

Forward-Looking Statements

 

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

 

 

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth in the summary risks noted below and under “Risk Factors” attached hereto as Exhibit 99.1:

 

 

 

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

 

Company Overview

 

CVR Energy, Inc. and, unless the context requires otherwise, its subsidiaries (“CVR”, the “Company”, “we”, “us” or “our”) is an independent refiner and marketer of high value transportation fuels. In addition, until the completion of the initial public offering of CVR Partners (the “Partnership”), a limited partnership which produces nitrogen fertilizers, ammonia and UAN, as discussed in further detail below, we owned all of the interests (other than the managing general partner interest and associated incentive distribution rights) in the Partnership.

 

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

 

As of December 31, 2010, approximately 40% of our outstanding shares were owned by certain funds affiliated with Goldman Sachs & Co. and Kelso & Company, L.P. (“GS” and “Kelso”, respectively), through their respective ownership of CALLC II and CALLC. On February 8, 2011, CALLC and CALLC II completed a sale of our common stock into the public market pursuant to a registered public offering. As a result of this offering, GS sold into the public market its remaining ownership interests in CVR Energy. Additionally, Kelso reduced its interest in the Company and as of the date of this report beneficially owns approximately 9% of all shares outstanding.

On April 13, 2011, the Partnership completed its initial public offering of its common units representing limited partner interests (the “Offering”). The Partnership sold 22,080,000 common units (such amount includes commitments issued pursuant to the exercise of the underwriters over-allotment option) at a price of $16.00 per common unit, resulting in gross proceeds (including the gross proceeds from the exercise of the underwriters’ over-allotment option) of $353.3 million prior to underwriting discount and other offering costs. The Partnership’s units are listed on the New York Stock Exchange and are traded under the symbol “UAN.” In connection with the Offering the Partnership paid approximately $24.7 in underwriting fees and incurred approximately $4.0 million of other offering costs. Approximately $5.7 million was paid to an affiliate of GS acting as joint book-running managers. Until completion of the February 2011 secondary offering (described above), an affiliate of GS was a stockholder and a related party of the Company. As a result of the Offering, CVR indirectly owns 69.8% of the Partnership’s outstanding common units and 100% of the Partnership’s general partner with its non-economic general partner interest.

 

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

 

Petroleum business.  Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas. In addition, supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 35,000 bpd serving Kansas, Oklahoma, western Missouri and southwestern Nebraska, (2) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and at throughput terminals on Magellan and NuStar Energy, LP’s (“NuStar”) refined products distribution systems and (3) a 145,000 bpd pipeline system that transports crude oil to our refinery with 1.2 million barrels of associated company-owned storage tanks and an additional 2.7 million barrels of leased storage capacity located at Cushing, Oklahoma. The crude oil gathering system is supported by approximately 300 miles of Company owned and leased pipeline.

 

Our refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Cushing is supplied by numerous pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude oil variety in the world capable of being transported by pipeline. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Operating, L.P. and NuStar.

 

Crude oil is supplied to our refinery through our gathering system and by a Plains pipeline from Cushing, Oklahoma. We maintain capacity on the Spearhead and Keystone pipelines (as discussed more fully in Note 11 to the financial statements) from Canada and have access to foreign and deepwater domestic crude oil via the Seaway Pipeline system from the U.S. Gulf Coast to Cushing. We also maintain leased storage in Cushing to facilitate optimal crude oil purchasing and blending. Our refinery blend consists of a combination of crude oil grades, including onshore and offshore domestic grades, various Canadian medium and heavy sours and sweet synthetics and from time to time a variety of South American, North Sea, Middle East and West African imported grades. The access to a variety of crude oils coupled with the complexity of our refinery allows us to purchase crude oil at a discount to WTI. Our consumed crude cost discount to WTI for the first quarter of 2011 was $(5.65) per barrel compared to $(3.02) per barrel in the first quarter of 2010.

 

Nitrogen fertilizer business.  The nitrogen fertilizer business consists of our interest in the Partnership, which, after its initial public offering, is controlled by us. The nitrogen fertilizer business consists of a nitrogen fertilizer manufacturing facility that is the only operation in North America that utilizes a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer. The facility includes a 1,225 ton-per-day ammonia unit, a 2,025 ton-per-day UAN unit and a gasifier complex having a capacity of 84 million standard cubic feet per day. The gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving reliability. The nitrogen fertilizer business upgrades a majority of the ammonia it produces to higher margin UAN fertilizer, an aqueous solution of urea and ammonium nitrate

which has historically commanded a premium price over ammonia. In 2010, the nitrogen fertilizer business produced 392,745 tons of ammonia, of which approximately 60% was upgraded into 578,272 tons of UAN.

 

The primary raw material feedstock utilized in our nitrogen fertilizer production process is pet coke, which is produced during the crude oil refining process. In contrast, substantially all of the nitrogen fertilizer businesses’ competitors use natural gas as their primary raw material feedstock. Historically, pet coke has been significantly less expensive than natural gas on a per ton of fertilizer produced basis and pet coke prices have been more stable when compared to natural gas prices. By using pet coke as the primary raw material feedstock instead of natural gas, the nitrogen fertilizer business has historically been the lowest cost producer and marketer of ammonia and UAN fertilizers in North America. The nitrogen fertilizer business currently purchases most of its pet coke from CVR pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. During the past five years, over 70% of the pet coke utilized by the nitrogen fertilizer plant was produced and supplied by CVR’s crude oil refinery.

 

Major Influences on Results of Operations

 

Petroleum Business

 

Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in, first-out (“FIFO”) accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.

 

Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors’ facilities, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuel standards, proposed climate change laws and regulations, and increased mileage standards for vehicles.

 

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

Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refinery has certain feedstock costs and logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refinery margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil and the price of WTI. The spread is referred to as our consumed crude oil differential. Our refinery margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the WTS differential to WTI and the West Canadian Select (“WCS”) differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The correlation between our consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil we purchase as a percent of our total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.

 

We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices in our region include the logistics cost for U.S. Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in our refinery is that prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra Low Sulfur Diesel basis. If both gasoline and Ultra Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.

 

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption for the three months ended March 31, 2011, a $1.00 change of natural gas pricing would have increased or decreased our natural gas costs for the quarter by $1.0 million.

 

Because petroleum feedstocks and products are essentially commodities, we have no control over the changing market. Therefore, the lower the target inventory we are able to maintain significantly reduces the impact of commodity price volatility on our petroleum product inventory position relative to other refiners. This target inventory position is generally not hedged. To the extent our inventory position deviates from the target level, we consider risk mitigation activities usually through the purchase or sale of futures contracts on the NYMEX. Our hedging activities carry customary time, location and product grade basis risks generally associated with hedging activities. Because most of our titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory have a major effect on our financial results unless the market value of our target inventory is increased above cost.

 

Consistent, safe, and reliable operations at our refinery are key to our financial performance and results of operations. Unplanned downtime at our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The refinery generally undergoes a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The next turnaround for our refinery is being conducted in two separate phases. The first phase will commence and conclude in the fourth quarter of 2011. The second phase of the turnaround will commence and conclude in the first quarter of 2012.

 

Our refinery experienced an equipment malfunction and small fire in connection with its FCCU on December 28, 2010, which led to reduced crude throughput and repair cost of approximately $1.9 million, net

of the insurance receivable recorded for the three months ended March 31, 2011. We used the resulting downtime to perform certain turnaround activities which had otherwise been scheduled for later in 2011, along with opportunistic maintenance, which cost approximately $4.0 million in total. 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. We estimate that approximately 1.9 million barrels of crude oil processing were lost in the first quarter of 2011 due to this incident.

 

Nitrogen Fertilizer Business

 

In the nitrogen fertilizer business, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, on-stream factors and direct operating expenses. Unlike its competitors, the nitrogen fertilizer business does not use natural gas as a feedstock and uses a minimal amount of natural gas as an energy source in its operations. As a result, volatile swings in natural gas prices have a minimal impact on its results of operations. Instead, our adjacent refinery supplies the nitrogen fertilizer business with most of the pet coke feedstock it needs pursuant to a long-term pet coke supply agreement entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, and the extent of government intervention in agriculture markets.

 

Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities. An expansion or upgrade of competitors’ facilities, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

 

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

 

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

 

In order to assess the operating performance of the nitrogen fertilizer business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs.

 

We and other competitors in the U.S. farm belt share a significant transportation cost advantage when compared to our out-of-region competitors in serving the U.S. farm belt agricultural market. In 2010, approximately 45% of the corn planted in the United States was grown within a $35/UAN ton freight train rate of the nitrogen fertilizer plant. We are therefore able to cost-effectively sell substantially all of our products in the higher margin agricultural market, whereas a significant portion of our competitors’ revenues is derived from the lower margin industrial market. Our location on Union Pacific’s main line increases our transportation cost advantage by lowering the costs of bringing our products to customers, assuming freight rates and pipeline tariffs for U.S. Gulf Coast importers as recently in effect. Our products leave the plant either in trucks for direct shipment to customers or in railcars for destinations located principally on the Union Pacific Railroad, and we do not incur any intermediate transfer, storage, barge freight or pipeline freight charges. We estimate that our plant enjoys a transportation cost advantage of approximately $25 per ton over competitors located in the U.S. Gulf Coast. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.

The value of nitrogen fertilizer products is also an important consideration in understanding our results. During 2010, the nitrogen fertilizer business upgraded approximately 60% of its ammonia production into UAN, a product that presently generates a greater value than ammonia. UAN production is a major contributor to our profitability.

 

The direct operating expense structure of the nitrogen fertilizer business also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These fixed costs have averaged approximately 86% of direct operating expenses over the 24 months ended December 31, 2010.

 

Consistent, safe, and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $3 million to $5 million per turnaround. The nitrogen fertilizer plant underwent a turnaround in the fourth quarter of 2010, at a cost of approximately $3.5 million. The next facility turnaround is currently scheduled for the fourth quarter of 2012.

 

Agreements Between CVR Energy and the Partnership

 

In connection with our initial public offering and the transfer of the nitrogen fertilizer business to the Partnership in October 2007, we entered into a number of agreements with the Partnership that govern the business relations between the parties. These include the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to the nitrogen fertilizer business; a services agreement, in which our management operates the nitrogen fertilizer business; a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; an easement agreement; an environmental agreement; and a lease agreement pursuant to which we lease office space and laboratory space to the Partnership. Certain of these agreements were amended and/or restated in connection with the Offering.

 

The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from our adjacent crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder on the open market. The price the nitrogen fertilizer business 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.

 

Vitol Agreement

 

On March 30, 2011, CRRM and Vitol Inc. (“Vitol”) entered into a Crude Oil Supply Agreement (the “Vitol Agreement”). This agreement replaced the previous supply agreement between CRRM and Vitol dated December 2, 2008, as amended, which was terminated by Vitol and CRRM on March 30, 2011.

 

The Vitol Agreement provides that CRRM will continue to obtain all of the crude oil for CRRM’s refinery through Vitol, other than the crude oil gathered by us from Kansas, Missouri, North Dakota and Oklahoma, Wyoming and all adjacent states. CRRM and Vitol will continue to work together to identify crude

oil and pricing terms that meet CRRM’s crude oil requirements. CRRM and/or Vitol will negotiate the costs of each barrel of crude oil that is purchased from third-party crude oil suppliers. Vitol purchases all such crude oil, executes all third-party sourcing transactions and provides transportation and other logistical services for the subject crude oil. Vitol then sells such crude oil and delivers the same to CRRM. Title and risk of loss for all crude oil purchased by CRRM through the Vitol Agreement passes to CRRM upon delivery to the Company’s Broome Station, located near Caney, Kansas. CRRM generally pays Vitol a fixed origination fee per barrel over the negotiated cost of each barrel purchased. The Vitol Agreement commenced March 30, 2011 and extends for an initial term ending December 31, 2013, but also allows for automatic renewal for successive one-year terms.

 

Factors Affecting Comparability of Our Financial Results

 

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

 

Refinancing and Prior Indebtedness

 

On February 22, 2011, CRLLC entered into a $250.0 million asset-backed revolving credit agreement (“ABL credit facility”). The ABL credit facility replaced the first priority credit facility which was terminated. As a result of the termination of the first priority credit facility, we wrote-off a portion of our previously deferred financing costs of approximately $1.9 million. This write-off is reflected on the Condensed Consolidated Statements of Operations as a loss on extinguishment of debt for the three months ended March 31, 2011. In connection with the ABL credit facility, CRLLC incurred approximately $5.0 million of fees that were deferred and are to be amortized over the term of the credit facility on a straight-line basis.

 

In January 2010, we made a voluntary unscheduled principal payment of $20.0 million on our tranche D term loans. In addition, we made a second voluntary unscheduled principal payment of $5.0 million in February 2010, reducing our tranche D term loans’ outstanding principal balance to $453.3 million. In connection with these voluntary prepayments, we paid a 2.0% premium totaling $0.5 million to the lenders of our first priority credit facility. In April 2010, we paid off the remaining $453.0 million tranche D term loans. This payoff was made possible by the issuance 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”). In connection with the payoff, we paid a 2.0% premium totaling approximately $9.1 million.

 

On March 12, 2010, CRLLC entered into a fourth amendment to its first priority credit facility. The amendment, among other things, provided CRLLC the opportunity to issue junior lien debt, subject to certain conditions, including, but not limited to, a requirement that 100% of the proceeds be used to prepay the tranche D term loans. The amendment also provided CRLLC the ability to issue up to $350.0 million of first lien debt, subject to certain conditions, including, but not limited to, a requirement that 100% of the proceeds be used to prepay all of the remaining tranche D term loans.

 

In connection with the fourth amendment, CRLLC incurred lender fees of approximately $4.5 million. These fees were recorded as deferred financing costs in the first quarter of 2010. In addition, CRLLC incurred third party costs of approximately $1.5 million primarily consisting of administrative and legal costs. Of the third party costs incurred we expensed $1.1 million in 2010 and the remaining $0.4 million was recorded as additional deferred financing costs.

 

On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility with a group of lenders. 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. There is no scheduled amortization and the credit facility matures in April 2016. The Partnership, upon the 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, letter of credit issuances and general needs of CRNF.

 

Share-Based Compensation

 

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

 

Also, in conjunction with the initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment by an investor for stock-based compensation granted to employees of an equity method investee. In addition, these awards are subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment for equity instruments that are issued to other than employees for acquiring or in conjunction with selling goods or services. In accordance with this accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived under the same methodology as the Phantom Unit Plans, as remeasured at each reporting date until the awards vest. Certain override units were fully vested during the second quarter of 2010. Subsequent to the second quarter of 2010, there was no additional expense incurred with respect to these awards. For the three months ended March 31, 2011 and 2010, we increased compensation expense by $16.9 million and $7.1 million, respectively, as a result of the phantom and override unit share-based compensation awards. We expect to incur additional incremental share-based compensation expense with respect to unvested override units and phantom awards to the extent our common stock price increases.

 

Through the Company’s Long-Term Incentive Plan, shares of non-vested common stock may be awarded to the Company’s employees, officers, consultants, advisors and directors. Non-vested shares, when granted, are valued at the closing market price of CVR’s common stock and the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. For the three months ended March 31, 2011 and 2010, we incurred compensation expense of $2.2 million and $0.2 million, respectively, related to non-vested share-based compensation awards.

 

Fertilizer Plant Property Taxes

 

The nitrogen fertilizer plant received a ten year 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 the 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 liability for the plant by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, and approximately $11.7 million for the year ended December 31, 2010. We do not agree with the county’s classification of the nitrogen fertilizer plant and are currently disputing it before the Kansas Court of Tax Appeals (“COTA”). However, we have fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008. The first payment in respect of CRNF’s 2010 property taxes was paid in December 2010 and the second payment was paid in May 2011. These amounts are reflected as a direct operating expense in the nitrogen fertilizer business’ financial results. An evidentiary hearing before COTA occurred during the first quarter of 2011 regarding our property tax claims for the year ended December 31, 2008. We believe COTA is likely to

issue a ruling sometime during 2011. However, the timing of a ruling in the case is uncertain, and there can be no assurance we will receive a ruling in 2011. If we are 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 the nitrogen fertilizer business, which could have a material positive effect on its results of operations. If we are not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, we expect that the nitrogen fertilizer business will pay taxes at or below the elevated rates described above.

 

Noncontrolling Interest

 

In connection with the April 2011 initial public offering of the Partnership, the noncontrolling interests representing the incentive distribution rights (“IDRs”) of the managing general partner were purchased by the Partnership and the IDRs were subsequently extinguished. The payment for the IDRs was paid to owners of CALLC III, which included GS, Kelso 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 an approximately 30.2% interest in the net book value of the Partnership at the time of the Offering. Effective with the Offering, CVR Energy’s noncontrolling interest reflected on the consolidated balance sheet will be impacted by approximately 30.2% of the net income of the Partnership and related distributions for each future reporting period. The revenue and expenses from the Partnership will continue to be consolidated with CVR Energy’s statement of operations based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR Energy; and therefore has the ability to control the activities of the Partnership. However, the percentage of ownership held by the public unitholders will be reflected as net income attributable to noncontrolling interest in our consolidated statement of operations and will reduce consolidated net income to derive net income attributable to CVR Energy, Inc.

 

Publicly Traded Partnership Expenses

 

We expect that our general and administrative expenses will increase due to the costs of the Partnership operating as a publicly traded company, including costs associated with SEC reporting requirements, including annual and quarterly reports to unit holders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses will approximate $3.5 million per year, excluding the costs associated with the costs of the initial implementation of our Sarbanes-Oxley Section 404 internal controls review and testing. Our future consolidated financial statements will reflect the impact of these expenses, which will affect the comparability of its post-offering results with its financial statements from periods prior to the completion of the initial public offering.

 

September 2010 UAN Vessel Rupture

 

On September 30, 2010, our 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. The nitrogen fertilizer facility had previously scheduled a major turnaround to begin on October 5, 2010. To minimize disruption and impact to the production schedule, the turnaround was accelerated. The turnaround was completed on October 29, 2010 with the gasification and ammonia units in operation. The fertilizer facility restarted production of UAN on November 16, 2010 and as of December 31, 2010 repairs to the facility as a result of the rupture were substantially complete. Besides adversely impacting UAN sales in the fourth quarter of 2010, the outage caused us to shift delivery of lower priced tons from the fourth quarter of 2010 to the first and second quarters of 2011.

 

Total gross costs recorded as of March 31, 2011 due to the incident were approximately $10.9 million for repairs and maintenance and other associated costs. We recorded an insurance receivable of $4.5 million under the property damage coverage of which approximately $4.3 million of insurance proceeds were received as of December 31, 2010 and the remaining $0.2 million was received in January 2011. Of the costs incurred, approximately $4.5 million were capitalized. We also recognized income of approximately $2.9 million from our business interruption insurance policy in the first quarter of 2011. We received approximately $2.3 million related to the business interruption claim and received the remaining $0.6 million in April 2011.

Distributions to Unitholders

 

Following the initial public offering, the Partnership intends to make cash distributions of all available cash it generates each quarter beginning with the quarter ending June 30, 2011, covering April 13, 2011, the closing of its initial public offering through June 30, 2011. Available cash for each quarter will be determined by the Partnership’s board of directors of its general partner following the end of such quarter. We expect that available cash for each quarter will generally equal the Partnership’s cash flow from operations for the quarter, less cash needed for maintenance, capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of the Partnership’s general partner deems necessary or appropriate. However, the board of directors of the general partner may modify the cash distribution policy at any time and the partnership agreement does not require the Partnership to make distributions at all.

 

Results of Operations

 

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three months ended March 31, 2011 and 2010. The summary financial data for our two operating segments does not include certain selling, general and administrative expenses and depreciation and amortization related to our corporate offices. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” except for the balance sheet data as of December 31, 2010, is unaudited.