Delaware | 001-33492 | 61-1512186 | ||
(State or other jurisdiction of incorporation) |
(Commission File Number) | (I.R.S. Employer Identification Number) |
Item 2.02. | Results of Operations and Financial Condition. |
Item 9.01. | Financial Statements and Exhibits. |
99.1
|
Press release dated November 2, 2011, issued by CVR Energy, Inc. |
CVR Energy, Inc. |
||||
By: | /s/ Edward Morgan | |||
Edward Morgan, | ||||
Chief Financial Officer and Treasurer | ||||
Investor Relations:
|
Media Relations: | |
Jay Finks
|
Steve Eames | |
CVR Energy, Inc.
|
CVR Energy, Inc. | |
281-207-3588
|
281-207-3550 | |
InvestorRelations@CVREnergy.com
|
MediaRelations@CVREnergy.com |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions, except share data) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Consolidated Statement of Operations Data: |
||||||||||||||||
Net sales |
$ | 1,352.0 | $ | 1,031.2 | $ | 3,966.9 | $ | 2,931.6 | ||||||||
Cost of product sold* |
1,026.0 | 889.9 | 3,086.2 | 2,584.4 | ||||||||||||
Direct operating expenses* |
74.6 | 52.5 | 209.3 | 175.5 | ||||||||||||
Insurance recovery business interruption |
(0.5 | ) | | (3.4 | ) | | ||||||||||
Selling, general and administrative expenses* |
17.7 | 16.4 | 69.0 | 48.6 | ||||||||||||
Depreciation and amortization |
22.0 | 21.9 | 66.1 | 64.8 | ||||||||||||
Operating income |
$ | 212.2 | $ | 50.5 | $ | 539.7 | $ | 58.3 | ||||||||
Interest expense and other financing costs |
(13.8 | ) | (13.9 | ) | (41.2 | ) | (36.6 | ) | ||||||||
Gain (loss) on derivatives, net |
(9.9 | ) | (1.0 | ) | (25.1 | ) | 7.8 | |||||||||
Loss on extinguishment of debt |
| | (2.1 | ) | (15.1 | ) | ||||||||||
Other income, net |
0.4 | 0.5 | 1.4 | 2.4 | ||||||||||||
Income before income tax expense |
$ | 188.9 | $ | 36.1 | $ | 472.7 | $ | 16.8 | ||||||||
Income tax expense |
68.6 | 12.9 | 172.5 | 4.8 | ||||||||||||
Net income |
$ | 120.3 | $ | 23.2 | $ | 300.2 | $ | 12.0 | ||||||||
Net income attributable to noncontrolling interest |
11.0 | | 20.3 | | ||||||||||||
Net income attributable to CVR Energy stockholders |
109.3 | 23.2 | 279.9 | 12.0 |
* | Amounts shown are exclusive of depreciation and amortization. |
Basic earnings per share |
$ | 1.26 | $ | 0.27 | $ | 3.24 | $ | 0.14 | ||||||||
Diluted earnings per share |
$ | 1.25 | $ | 0.27 | $ | 3.19 | $ | 0.14 | ||||||||
Weighted average common shares outstanding |
||||||||||||||||
Basic |
86,549,846 | 86,343,102 | 86,462,668 | 86,336,205 | ||||||||||||
Diluted |
87,743,600 | 87,013,575 | 87,772,169 | 86,677,325 |
As of September 30, | As of December 31, | |||||||
2011 | 2010 | |||||||
(in millions) | ||||||||
(unaudited) | ||||||||
Balance Sheet Data: |
||||||||
Cash and cash equivalents |
$ | 898.5 | $ | 200.0 | ||||
Working capital |
1,059.4 | 333.6 | ||||||
Total assets |
2,508.3 | 1,740.2 | ||||||
Total debt, including current portion |
591.8 | 477.0 | ||||||
Total CVR
Energy stockholders equity |
1,083.6 | 689.6 | ||||||
Noncontrolling interest |
148.0 | 10.6 |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Other Financial Data: |
||||||||||||||||
Cash flows provided by operating activities |
$ | 183.3 | $ | 105.4 | $ | 345.9 | $ | 151.1 | ||||||||
Cash flows used in investing activities |
(23.1 | ) | (6.2 | ) | (43.8 | ) | (23.0 | ) | ||||||||
Cash flows provided by (used in) financing activities |
(9.7 | ) | (0.1 | ) | 396.3 | (2.6 | ) | |||||||||
Net cash flow |
$ | 150.5 | $ | 99.1 | $ | 698.4 | $ | 125.5 |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions, except per share data) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Non-GAAP Measures: |
||||||||||||||||
Reconciliation of Net Income to Adjusted Net Income: |
||||||||||||||||
Net Income attributable to CVR Energy stockholders |
$ | 109.3 | $ | 23.2 | $ | 279.9 | $ | 12.0 | ||||||||
Adjustments: |
||||||||||||||||
FIFO impact (favorable) unfavorable, net of taxes (1) |
15.8 | (2.1 | ) | 0.9 | 1.6 | |||||||||||
Share-based compensation, net of taxes (2) |
1.5 | 3.3 | 16.5 | 7.1 | ||||||||||||
Loss on extinguishment of debt, net of taxes (3) |
| | 1.2 | 9.1 | ||||||||||||
Major scheduled turnaround expense, net of taxes (4) |
4.8 | 0.3 | 7.4 | 0.4 | ||||||||||||
Loss on disposition of assets, net of taxes (5) |
| | 0.9 | 0.8 | ||||||||||||
Unrealized (gain) loss on derivatives, net of taxes (6) |
6.0 | 0.7 | 4.1 | (0.5 | ) | |||||||||||
Adjusted net income (7) |
$ | 137.4 | $ | 25.4 | $ | 310.9 | $ | 30.5 | ||||||||
Adjusted net income per diluted share |
$ | 1.57 | $ | 0.29 | $ | 3.54 | $ | 0.35 |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions, except operating statistics) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Petroleum Business Financial Results: |
||||||||||||||||
Net sales |
$ | 1,284.4 | $ | 986.2 | $ | 3,772.3 | $ | 2,794.2 | ||||||||
Cost of product sold* |
1,024.5 | 879.0 | 3,077.5 | 2,560.1 | ||||||||||||
Direct operating expenses* (8)(9) |
54.5 | 35.3 | 144.0 | 114.8 | ||||||||||||
Depreciation and amortization |
17.0 | 16.9 | 50.9 | 49.5 | ||||||||||||
Gross profit (10) |
$ | 188.4 | $ | 55.0 | $ | 499.9 | $ | 69.8 | ||||||||
Plus direct operating expenses* |
54.5 | 35.3 | 144.0 | 114.8 | ||||||||||||
Plus depreciation and amortization |
17.0 | 16.9 | 50.9 | 49.5 | ||||||||||||
Refining margin (11) |
$ | 259.9 | $ | 107.2 | $ | 694.8 | $ | 234.1 | ||||||||
FIFO impact (favorable) unfavorable (1) |
26.2 | (3.5 | ) | 1.5 | 2.6 | |||||||||||
Refining margin adjusted for FIFO impact (12) |
$ | 286.1 | $ | 103.7 | $ | 696.3 | $ | 236.7 | ||||||||
Operating income |
$ | 179.8 | $ | 46.6 | $ | 469.0 | $ | 44.1 | ||||||||
Adjusted Petroleum EBITDA (13) |
$ | 232.0 | $ | 61.7 | $ | 525.2 | $ | 108.2 | ||||||||
Petroleum Key Operating Statistics: |
||||||||||||||||
Per crude oil throughput barrel: |
||||||||||||||||
Refining margin (11) |
$ | 25.03 | $ | 9.84 | $ | 23.77 | $ | 7.63 | ||||||||
FIFO impact (favorable) unfavorable (1) |
2.52 | (0.32 | ) | 0.05 | 0.08 | |||||||||||
Refining margin adjusted for FIFO impact (12) |
27.55 | 9.52 | 23.82 | 7.71 | ||||||||||||
Gross profit (10) |
18.14 | 5.05 | 17.10 | 2.28 | ||||||||||||
Direct operating expenses* (8) |
5.25 | 3.24 | 4.93 | 3.74 | ||||||||||||
Direct operating expenses per barrel sold* (9) |
5.19 | 2.93 | 4.71 | 3.38 | ||||||||||||
Barrels sold (barrels per day) (9) |
114,061 | 130,809 | 111,939 | 124,332 |
* | Amounts shown are exclusive of depreciation and amortization |
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||||||||||
Refining Throughput and Production Data: |
||||||||||||||||||||||||||||||||
(barrels per day) |
||||||||||||||||||||||||||||||||
Throughput: |
||||||||||||||||||||||||||||||||
Sweet |
91,498 | 78.8 | % | 95,570 | 74.2 | % | 85,401 | 75.8 | % | 90,461 | 74.6 | % | ||||||||||||||||||||
Light/medium sour |
994 | 0.8 | % | 3,876 | 3.0 | % | 598 | 0.5 | % | 6,623 | 5.5 | % | ||||||||||||||||||||
Heavy sour |
20,393 | 17.6 | % | 18,905 | 14.7 | % | 21,071 | 18.7 | % | 15,272 | 12.6 | % | ||||||||||||||||||||
Total crude oil throughput |
112,885 | 97.2 | % | 118,351 | 91.9 | % | 107,070 | 95.0 | % | 112,356 | 92.7 | % | ||||||||||||||||||||
All other feedstocks and blendstocks |
3,206 | 2.8 | % | 10,438 | 8.1 | % | 5,671 | 5.0 | % | 8,960 | 7.3 | % | ||||||||||||||||||||
Total throughput |
116,091 | 100.0 | % | 128,789 | 100.0 | % | 112,741 | 100.0 | % | 121,316 | 100.0 | % | ||||||||||||||||||||
Production: |
||||||||||||||||||||||||||||||||
Gasoline |
49,886 | 42.7 | % | 62,432 | 48.1 | % | 50,998 | 45.0 | % | 59,168 | 48.3 | % | ||||||||||||||||||||
Distillate |
50,189 | 43.0 | % | 53,404 | 41.1 | % | 47,368 | 41.8 | % | 49,912 | 40.8 | % | ||||||||||||||||||||
Other (excluding internally produced fuel) |
16,770 | 14.3 | % | 14,049 | 10.8 | % | 15,038 | 13.2 | % | 13,294 | 10.9 | % | ||||||||||||||||||||
Total refining production (excluding
internally produced fuel) |
116,845 | 100.0 | % | 129,885 | 100.0 | % | 113,404 | 100.0 | % | 122,374 | 100.0 | % | ||||||||||||||||||||
Product price (dollars per gallon): |
||||||||||||||||||||||||||||||||
Gasoline |
$ | 2.95 | $ | 2.05 | $ | 2.89 | $ | 2.07 | ||||||||||||||||||||||||
Distillate |
$ | 3.07 | $ | 2.13 | $ | 3.04 | $ | 2.12 | ||||||||||||||||||||||||
Market Indicators (dollars per barrel): |
||||||||||||||||||||||||||||||||
West Texas Intermediate
(WTI) NYMEX |
$ | 89.54 | $ | 76.21 | $ | 95.47 | $ | 77.69 | ||||||||||||||||||||||||
Crude Oil Differentials: |
||||||||||||||||||||||||||||||||
WTI less WTS
(light/medium sour) |
$ | 0.82 | $ | 2.16 | $ | 2.46 | $ | 1.96 | ||||||||||||||||||||||||
WTI less WCS (heavy sour) |
$ | 14.09 | $ | 19.52 | $ | 17.86 | $ | 14.74 | ||||||||||||||||||||||||
NYMEX Crack Spreads: |
||||||||||||||||||||||||||||||||
Gasoline |
$ | 32.01 | $ | 7.80 | $ | 26.04 | $ | 10.17 | ||||||||||||||||||||||||
Heating Oil |
$ | 35.82 | $ | 10.22 | $ | 28.51 | $ | 9.35 | ||||||||||||||||||||||||
NYMEX 2-1-1 Crack Spread |
$ | 33.92 | $ | 9.01 | $ | 27.27 | $ | 9.76 | ||||||||||||||||||||||||
PADD II Group 3 Basis: |
||||||||||||||||||||||||||||||||
Gasoline |
$ | (0.03 | ) | $ | 1.27 | $ | (1.21 | ) | $ | (1.42 | ) | |||||||||||||||||||||
Ultra Low Sulfur Diesel |
$ | 2.54 | $ | 2.91 | $ | 2.32 | $ | 1.74 | ||||||||||||||||||||||||
PADD II Group 3 Product Crack: |
||||||||||||||||||||||||||||||||
Gasoline |
$ | 31.98 | $ | 9.06 | $ | 24.82 | $ | 8.75 | ||||||||||||||||||||||||
Ultra Low Sulfur Diesel |
$ | 38.36 | $ | 13.13 | $ | 30.82 | $ | 11.08 | ||||||||||||||||||||||||
PADD II Group 3 2-1-1 |
$ | 35.17 | $ | 11.10 | $ | 27.82 | $ | 9.92 |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions, except as noted) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Nitrogen Fertilizer Business Financial Results: |
||||||||||||||||
Net sales |
$ | 77.2 | $ | 46.4 | $ | 215.3 | $ | 141.1 | ||||||||
Cost of product sold* |
10.9 | 10.8 | 28.2 | 27.7 | ||||||||||||
Direct operating expenses* |
20.1 | 17.2 | 65.4 | 60.7 | ||||||||||||
Insurance recovery business interruption |
(0.5 | ) | | (3.4 | ) | | ||||||||||
Depreciation and amortization |
4.7 | 4.5 | 13.9 | 13.9 | ||||||||||||
Operating income |
$ | 37.5 | $ | 10.6 | $ | 93.6 | $ | 30.0 | ||||||||
Adjusted Nitrogen Fertilizer EBITDA (13) |
$ | 43.3 | $ | 15.7 | $ | 114.0 | $ | 45.1 | ||||||||
Nitrogen Fertilizer Key Operating Statistics: |
||||||||||||||||
Production (thousand tons): |
||||||||||||||||
Ammonia (gross produced) (14) |
102.7 | 112.6 | 310.4 | 322.9 | ||||||||||||
Ammonia (net available for sale) (14) |
25.9 | 41.0 | 89.3 | 117.9 | ||||||||||||
UAN |
185.8 | 173.8 | 535.8 | 500.5 | ||||||||||||
Petroleum coke consumed (thousand tons) |
131.2 | 118.6 | 391.0 | 351.8 | ||||||||||||
Petroleum coke (cost per ton) |
$ | 43 | $ | 26 | $ | 30 | $ | 19 | ||||||||
Sales (thousand tons): |
||||||||||||||||
Ammonia |
22.6 | 33.4 | 83.5 | 115.2 | ||||||||||||
UAN |
179.2 | 178.9 | 524.7 | 506.9 | ||||||||||||
Total sales |
201.8 | 212.3 | 608.2 | 622.1 | ||||||||||||
Product pricing (plant gate) (dollars per ton) (15): |
||||||||||||||||
Ammonia |
$ | 568 | $ | 317 | $ | 569 | $ | 305 | ||||||||
UAN |
$ | 294 | $ | 168 | $ | 266 | $ | 180 | ||||||||
On-stream factors (16): |
||||||||||||||||
Gasification |
99.2 | % | 99.2 | % | 99.5 | % | 95.8 | % | ||||||||
Ammonia |
98.6 | % | 99.0 | % | 98.0 | % | 94.6 | % | ||||||||
UAN |
97.0 | % | 96.9 | % | 95.9 | % | 92.2 | % | ||||||||
Reconciliation to net sales (dollars in millions): |
||||||||||||||||
Freight in revenue |
$ | 6.0 | $ | 5.8 | $ | 16.1 | $ | 14.6 | ||||||||
Hydrogen revenue |
5.7 | | 11.9 | | ||||||||||||
Sales net plant gate |
65.5 | 40.6 | 187.3 | 126.5 | ||||||||||||
Total net sales |
$ | 77.2 | $ | 46.4 | $ | 215.3 | $ | 141.1 | ||||||||
Market Indicators: |
||||||||||||||||
Natural gas NYMEX (dollars per MMBtu) |
$ | 4.06 | $ | 4.38 | $ | 4.21 | $ | 4.52 | ||||||||
Ammonia Southern Plains (dollars per ton) |
$ | 619 | $ | 465 | $ | 609 | $ | 385 | ||||||||
UAN Mid Cornbelt (dollars per ton) |
$ | 401 | $ | 247 | $ | 373 | $ | 246 |
* | Amounts shown are exclusive of depreciation and amortization | |
(1) | First-in, first-out (FIFO) is the Companys basis for determining inventory value on a Generally Accepted Accounting Principles (GAAP) basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per |
crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period. Below are the gross and tax affected FIFO impact for the applicable periods: |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Petroleum: |
||||||||||||||||
FIFO impact (favorable) unfavorable |
$ | 26.2 | $ | (3.5 | ) | $ | 1.5 | $ | 2.6 | |||||||
Income tax expense (benefit) of FIFO |
(10.4 | ) | 1.4 | (0.6 | ) | (1.0 | ) | |||||||||
FIFO impact (favorable) unfavorable, net of taxes |
$ | 15.8 | $ | (2.1 | ) | $ | 0.9 | $ | 1.6 |
(2) | The Company has two classifications for share-based compensation awards. Phantom Unit Plan awards are accounted for as liability based awards. In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 718, Compensation Stock Compensation (ASC 718), the expense associated with these awards is based on the current fair value of the awards. These awards are remeasured at each reporting date until the awards are settled in their entirety. Override unit awards are accounted for as equity-classified awards using the guidance for non-employee awards prescribed by FASB Topic ASC 323 (ASC 323). ASC 323 includes guidance for the proper accounting by an investor for stock-based compensation granted to employees of an equity method investee. In addition, guidance set forth in FASB Topic ASC 505, provides the treatment related to accounting for equity investments that are issued other than to employees for acquiring, or in conjunction with selling goods or services. In accordance with that guidance, the expense associated with these awards is based on the current fair value of the awards. These awards are remeasured at each reporting date until the awards are vested (when the performance commitment is reached). The value of all of these awards can fluctuate significantly between periods. Subsequent to the second quarter of 2011, there will be no further compensation expense recorded associated with the Phantom Unit Plan awards and the override unit awards as both types of awards were settled in their entirety in the second quarter of 2011. |
Non-vested common stock awards are accounted for as equity-classified awards using the guidance provided by ASC 718. Non-vested common stock awards upon issuance typically vest over a three year period. Non-vested shares, when granted, are valued at the closing market price of CVRs common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the award. In connection with the initial public offering of CVR Partners, LP (the Partnership) in April 2011, the board of directors of the general partner of the Partnership adopted a Long-Term Incentive Plan (LTIP). Compensation expense associated with the fair value of these awards is amortized over the vesting period of the award. |
The compensation expense associated with our Phantom Unit Plan, override units, non-vested common stock awards, and the Partnerships LTIP awards is recorded in direct operating expenses, selling, general and administration expenses and other income. Below is a breakdown of the expense by Statement of Operations caption and by business segment. |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Share-based compensation recorded in
direct operating expenses: |
||||||||||||||||
Petroleum |
$ | 0.1 | $ | 0.1 | $ | 1.0 | $ | 0.2 | ||||||||
Nitrogen |
0.1 | 0.1 | 0.4 | 0.2 | ||||||||||||
Corporate |
| | | | ||||||||||||
$ | 0.2 | $ | 0.2 | $ | 1.4 | $ | 0.4 | |||||||||
Share-based compensation recorded in
selling, general and administrative expenses: |
||||||||||||||||
Petroleum |
$ | 0.7 | $ | 1.1 | $ | 7.0 | $ | 2.2 | ||||||||
Nitrogen |
0.8 | 0.6 | 6.0 | 1.1 | ||||||||||||
Corporate |
0.7 | 2.0 | 9.3 | 4.7 | ||||||||||||
$ | 2.2 | $ | 3.7 | $ | 22.3 | $ | 8.0 | |||||||||
Share-based compensation recorded in
other income |
| | (0.1 | ) | | |||||||||||
Total share-based compensation |
$ | 2.4 | $ | 3.9 | $ | 23.6 | $ | 8.4 | ||||||||
Income tax expense (benefit) of
share-based compensation |
(0.9 | ) | (0.6 | ) | (7.1 | ) | (1.3 | ) | ||||||||
Share-based compensation, net of taxes |
$ | 1.5 | $ | 3.3 | $ | 16.5 | $ | 7.1 |
(3) | In February 2011, the Company entered into an asset-backed revolving credit facility (ABL credit facility) and concurrently terminated its first priority credit facility. In connection with the terminated first priority credit facility, the Company recorded a loss on extinguishment of debt of approximately $1.9 million of previously deferred financing costs. In May 2011, the Company repurchased $2.7 million of its Senior Notes (Notes) at 103% of the aggregate principal balance. This repurchase was in conjunction with a tender offer in accordance with the terms of the Notes due to the initial public offering of CVR Partners. The premium and previously deferred financing costs associated with the Notes repurchased approximated $2.1 million and was recognized as a loss on extinguishment of debt in our Consolidated Statement of Operations for the nine months ended September 30, 2011. 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. 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. The premiums paid are reflected as a loss on extinguishment of debt in our Consolidated Statements of Operations. 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. In addition, previously deferred borrowing costs totaling approximately $5.4 million associated with the first priority credit facility term debt were also written off at that time. The Company also recognized approximately $0.1 million of third party costs at the time the Notes were issued. Other third party costs incurred at the time were deferred and will be amortized over the respective terms of the Notes. The premiums paid, previously deferred borrowing costs subject to write-off and immediately recognized third party expenses are reflected as a loss on extinguishment of debt in our Condensed Consolidated Statements of Operations. Below are the gross and tax affected loss on extinguishment of debt for the applicable periods: |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Loss on extinguishment of debt |
$ | | $ | | $ | 2.1 | $ | 15.1 | ||||||||
Income tax expense (benefit) of loss on
extinguishment of debt |
| | (0.9 | ) | (6.0 | ) | ||||||||||
Loss on extinguishment of debt, net of taxes |
$ | | $ | | $ | 1.2 | $ | 9.1 |
(4) | Represents expenses associated with a major scheduled turnaround for the refinery. |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Major schedule turnaround expense |
$ | 8.0 | $ | 0.4 | $ | 12.2 | $ | 0.6 | ||||||||
Income tax expense (benefit) of turnaround expense |
(3.2 | ) | (0.1 | ) | (4.8 | ) | (0.2 | ) | ||||||||
Major scheduled turnaround expense,
net of taxes |
$ | 4.8 | $ | 0.3 | $ | 7.4 | $ | 0.4 |
(5) | During the second quarter of 2011, the Company wrote-off amounts associated with certain Petroleum fixed assets. During the second quarter of 2010, the Company wrote-off an amount associated with a capital project. Below are the gross and tax affected impacts for the applicable periods: |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Loss on disposition of assets |
$ | | $ | | $ | 1.5 | $ | 1.3 | ||||||||
Income tax expense (benefit) of loss on
disposition of assets |
| | (0.6 | ) | (0.5 | ) | ||||||||||
Loss on disposition of assets, net of taxes |
$ | | $ | | $ | 0.9 | $ | 0.8 |
(6) | The Company enters into commodity derivative transactions to manage price risk on crude oil and other inventories and to fix margins on certain future production. The Company has not designated their commodity derivative transactions as hedge transactions. All changes in fair market value are reported in earnings immediately. Below are the gross and tax affected impacts for the applicable periods: |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Unrealized (gain)/loss on derivatives, net |
$ | 10.0 | $ | 1.2 | $ | 6.8 | $ | (0.8 | ) | |||||||
Income tax expense (benefit) of unrealized
(gain)/loss on derivatives, net |
(4.0 | ) | (0.5 | ) | (2.7 | ) | 0.3 | |||||||||
Unrealized (gain)/loss on derivatives, net of taxes |
$ | 6.0 | $ | 0.7 | $ | 4.1 | $ | (0.5 | ) |
(7) | Adjusted net income results from adjusting net income for items that the Company believes are needed in order to evaluate results in a more comparative analysis from period to period. For the three and nine months ended September 30, 2011 and |
2010, these items included, on an after tax basis, the Companys impact of the accounting for its inventory under FIFO, share-based compensation, loss on extinguishment of debt, major scheduled turnaround expenses, loss on disposition of fixed assets and unrealized (gain)/loss on derivatives, net. Adjusted net income is not a recognized term under GAAP and should not be substituted for net income (loss) as a measure of our performance but rather should be utilized as a supplemental measure of financial performance in evaluating our business. Management believes that adjusted net income provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance. | ||
(8) | Direct operating expense is presented on a per crude oil throughput basis. We utilize the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period to derive the metric. | |
(9) | Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refinery. We utilize the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric. | |
(10) | In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period. | |
(11) | Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating our refinerys performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold exclusive of depreciation and amortization) can be taken directly from our Statement of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin is important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance. | |
(12) | Refining margin per crude oil throughput barrel adjusted for FIFO impact is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization) adjusted for FIFO impacts. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. Refining margin adjusted for FIFO impact is a non-GAAP measure that we believe is important to investors in evaluating our refinerys performance as a general indication of the amount above our cost of product sold (taking into account the impact of our utilization of FIFO) that we are able to sell refined products. Our calculation of refining margin adjusted for FIFO impact may differ from calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. | |
(13) | Adjusted Petroleum and Nitrogen Fertilizer EBITDA represents operating income adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, major scheduled turnaround expenses, realized gain (loss) on derivatives, net, loss on disposition of fixed assets, depreciation and amortization and other income (expense). Adjusted EBITDA by operating segment results from operating income by segment adjusted for items that we believe are needed in order to evaluate results in a more comparative analysis from period to period. Adjusted EBITDA by operating segment is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that adjusted EBITDA by operating segment provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall financial, operational and economic performance. Below is a reconciliation of operating income to adjusted EBITDA for the petroleum and nitrogen fertilizer segments for the three and nine months ended September 30, 2011 and 2010: |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Petroleum: |
||||||||||||||||
Petroleum operating income (loss) |
$ | 179.8 | $ | 46.6 | $ | 469.0 | $ | 44.1 | ||||||||
FIFO impacts (favorable), unfavorable |
26.2 | (3.5 | ) | 1.5 | 2.6 | |||||||||||
Share-based compensation |
0.8 | 1.2 | 8.0 | 2.4 | ||||||||||||
Major scheduled turnaround expenses |
8.0 | 0.4 | 12.2 | 0.6 | ||||||||||||
Realized gain (loss) on derivatives, net |
0.1 | 0.1 | (18.3 | ) | 7.1 | |||||||||||
Loss on disposition of assets |
| | 1.5 | 1.3 | ||||||||||||
Depreciation and amortization |
17.0 | 16.9 | 50.9 | 49.5 | ||||||||||||
Other income (expense) |
0.1 | | 0.4 | 0.6 | ||||||||||||
Adjusted Petroleum EBITDA |
$ | 232.0 | $ | 61.7 | $ | 525.2 | $ | 108.2 |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Nitrogen Fertilizer: |
||||||||||||||||
Nitrogen Fertilizer operating income |
$ | 37.5 | $ | 10.6 | $ | 93.6 | $ | 30.0 | ||||||||
Share-based compensation |
0.9 | 0.7 | 6.4 | 1.3 | ||||||||||||
Depreciation and amortization |
4.7 | 4.5 | 13.9 | 13.9 | ||||||||||||
Other income (expense) |
0.2 | (0.1 | ) | 0.1 | (0.1 | ) | ||||||||||
Adjusted Nitrogen Fertilizer EBITDA |
$ | 43.3 | $ | 15.7 | $ | 114.0 | $ | 45.1 |
(14) | The gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. The net tons available for sale represent the ammonia available for sale that was not upgraded into UAN. | |
(15) | Plant gate sales per ton represent net sales less freight and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry. | |
(16) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of the Linde air separation unit outage and the reactor outage, the on-stream factors would have been 99.2% for gasifier, 99.5% for ammonia, and 97.4% for UAN for three months ended September 30, 2010 and 98.0% for gasifier, 97.3% for ammonia, and 95.0% for UAN for nine months ended September 30, 2010. The on-stream factors would have been 100% for gasifier, 99.6% for ammonia, and 97.9% for UAN for three months ended September 30, 2011 and 99.8% for gasifier, 98.3% for ammonia, and 96.3% for UAN for nine months ended September 30, 2011, as adjusted to exclude the impact of a Linde air separation unit outage. |