Exhibit 99.1
CVR Energy Posts Second Quarter Earnings
Of $124.9 Million, or $1.42 Per Share
Of $124.9 Million, or $1.42 Per Share
SUGAR LAND, Texas (Aug. 3, 2011) — CVR Energy, Inc. (NYSE: CVI), a refiner and marketer of
petroleum fuels and the majority owner of a nitrogen fertilizer products manufacturer, today
reported second quarter 2011 net income attributable to CVR Energy stockholders of $124.9 million,
or $1.42 per fully diluted share, on net sales of
$1,447.7 million. The 2011 results compared to net income of $1.2 million, or 1 cent per fully diluted share, on
sales of $1,005.9 million for the second quarter in 2010.
For the first six months of 2011, the
company reported net income attributable to CVR Energy stockholders of $170.7 million, or $1.94 per
fully diluted share, on net sales of $2,615.0 million compared to an $11.2 million loss, or a loss
of 13 cents per share, on net sales of $1,900.4 million, for the
first six months of 2010.
“Increased margins for petroleum products and improving prices for nitrogen fertilizers lifted
us to record quarterly results,” said Chief Executive Officer Jack Lipinski. “Other than a
reduction in crude run rates because of an issue with the continuous catalytic reformer (CCR)
midway through the quarter, both plants ran well, allowing us to capture these high margins.
“In addition, early in the quarter we completed an initial public offering (IPO) of the CVR
Partners, LP, nitrogen fertilizer master limited partnership, unlocking the value of that business
and providing liquidity to grow the MLP,” Lipinski said. “CVR Energy retains 69.8 percent of the
common units in this master limited partnership and will receive proportional distributions from
CVR Partners.”
Consolidated
adjusted net income for the second quarter 2011 was
$130.3 million, or $1.48 per diluted
share. Major items impacting the 2011 second quarter adjusted net income were an unfavorable
impact from First In-First Out (FIFO) accounting, net of taxes, of $2.5 million; share-based
compensation, net of taxes, of $1.3 million; and several other one-time adjustments totaling $1.6
million, after tax.
For comparison, adjusted net income was $19.2 million in the second quarter of 2010. Major items
impacting the 2010 second quarter adjusted net income were an unfavorable impact from FIFO, net of
taxes, of $10.6 million; a reversal of share-based compensation, net of taxes, of $2.2 million; and several other
adjustments totaling $9.6 million.
As of
June 30, 2011, CVR Energy had cash and cash equivalents of $748.0 million compared to cash
and cash equivalents at year end 2010 of $200 million. In addition, the company carried excess
crude oil and product inventories of $48 million at the end of the second quarter 2011, compared to
excess inventories of $14 million at the end of the year 2010.
On July 26, 2011, the board of directors of the general partner of CVR Partners declared a
distribution of 40.7 cents per common unit, payable on Aug. 12, 2011, to unit holders of
record on Aug. 5, 2011. This announced distribution will reduce by
$9.0 million CVR Energy’s cash
and cash equivalents held on the payment date.
Petroleum Business
The petroleum business reported second quarter 2011 operating income of $183.5 million on net sales
of $1,376.7 million compared to operating income of $4.6 million on net sales of $951.3 million in
the second quarter of 2010. The results for the second quarter 2011 reflected an unfavorable
impact from FIFO accounting of $4.1 million, compared to an unfavorable impact of $17.5 million in
the same period of 2010. For the first six months of 2011, the petroleum segment had an operating
income of $289.2 million compared to an operating loss of $2.4 million for the first six months in
2010.
Adjusted EBITDA for the petroleum segment for the second quarter of 2011 was $208.4 million
compared to adjusted EBITDA of $46.5 million in the second quarter of 2010.
For the second quarter, the refinery had total crude oil throughput of 109,486 barrels per day,
compared with 113,431 barrels per day of crude during the second quarter of 2010. Including all
other feed and blend stocks, the refinery had total throughput of 116,459 barrels per day in the
second quarter of 2011 compared to total throughput of 121,867 in the second quarter of 2010.
Maintenance issues with the refinery’s CCR unit midway in the second quarter 2011 accounted for
most of the drop in throughput.
Refining margin per crude oil throughput barrel was $25.49 in the second quarter of 2011 compared
to $6.70 during the same period in 2010. Gross profit per crude oil throughput barrel was $19.36
in the second quarter of 2011 compared to $1.13 per crude oil throughput barrel during the same
period in 2010.
Direct operating expense, exclusive of depreciation and amortization, for the second quarter 2011
was $4.09 per barrel sold, as compared to $3.63 per barrel sold in the second quarter of 2010.
This increase was primarily attributable to higher prices in 2011 as well as unplanned maintenance
costs related to the outage at the CCR during the quarter.
Nitrogen Fertilizers Business
The
fertilizer business reported second quarter 2011 operating income of $39.3 million
on net sales of $80.7 million, compared to operating income of $16.5 million on net sales of $56.3
million during the equivalent period in 2010. For the first six months of 2011, operating income
was $56.1 million compared to operating income of $19.5 million in the first six months in 2010.
Adjusted EBITDA for the fertilizer segment was $45.0 million in the second quarter of 2011 compared
to adjusted EBITDA of $20.6 million for the same period in 2010.
On-stream factors for the nitrogen fertilizer plant were 99.3 percent for the gasifier, 98.5
percent for the ammonia synthesis loop, and 97.6 percent for the UAN facility.
For the second quarter 2011, average realized plant gate prices for ammonia and UAN were $574 per
ton and $300 per ton respectively, compared to $312 per ton and $205 per ton respectively for the
equivalent period in 2010.
The nitrogen fertilizer business produced 102,300 tons of ammonia during the second quarter of 2011, of which
28,200 net tons were available for sale while the rest was upgraded to 179,400 tons of more highly
valued UAN. In the 2010 second quarter, the plant produced 105,200 tons of ammonia with 38,700 net
tons available for sale and the remainder upgraded to 162,900 tons of UAN.
# # #
This news release contains forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. You can generally identify forward-looking statements by our use of forward-looking
terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,”
“may,” “might,” “plan,” “potential,” “predict,” “seek,” “should,” or “will,” or the negative
thereof or other variations thereon or comparable terminology. These forward-looking statements are
only predictions and involve known and unknown risks and uncertainties, many of which are beyond
our control. For a discussion of risk factors which may affect our results, please see the risk
factors and other disclosures included in our Annual Report on Form 10-K for the year ended Dec.
31, 2010, and any subsequently filed quarterly reports on Form 10-Q. These risks may cause our
actual results, performance or achievements to differ materially from any future results,
performance or achievements expressed or implied by these forward-looking statements. Given these
risks and uncertainties, you are cautioned not to place undue reliance on such forward-looking
statements. The forward-looking statements included in this press release are made only as of the
date hereof. The Company undertakes no duty to update its forward-looking statements.
About CVR Energy, Inc.
Headquartered in Sugar Land, Texas, CVR Energy, Inc.’s subsidiary and affiliated businesses include
an independent refiner that operates a 115,000 barrel per day refinery in Coffeyville, Kan., and
markets high value transportation fuels supplied to customers through tanker trucks and pipeline
terminals, and a crude oil gathering system serving central Kansas, Oklahoma, western Missouri and
southwest Nebraska. In addition, CVR Energy subsidiaries own a majority interest in and serve as
the general partner of CVR Partners, LP, a producer of ammonia and urea ammonium nitrate, or UAN,
fertilizers.
For further information, please contact:
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 |
CVR Energy, Inc.
The following tables summarize the financial data and key operating statistics for CVR Energy
and our two operating segments for the three and six months ended June 30, 2011 and 2010. Select
balance sheet data is as of June 30, 2011 and December 31, 2010.
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions, except share data) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Consolidated Statement of Operations Data: |
||||||||||||||||
Net sales |
$ | 1,447.7 | $ | 1,005.9 | $ | 2,615.0 | $ | 1,900.4 | ||||||||
Cost of product sold* |
1,123.4 | 891.7 | 2,060.2 | 1,694.5 | ||||||||||||
Direct operating expenses* |
66.2 | 62.5 | 134.5 | 123.1 | ||||||||||||
Insurance recovery — business interruption |
— | — | (2.9 | ) | — | |||||||||||
Selling, general and administrative expenses* |
18.2 | 10.8 | 51.5 | 32.2 | ||||||||||||
Net costs associated with flood |
— | — | 0.1 | — | ||||||||||||
Depreciation and amortization |
22.0 | 21.5 | 44.1 | 42.8 | ||||||||||||
Operating income |
$ | 217.9 | $ | 19.4 | $ | 327.5 | $ | 7.8 | ||||||||
Interest expense and other financing costs |
(14.2 | ) | (12.8 | ) | (27.4 | ) | (22.7 | ) | ||||||||
Gain (loss) on derivatives, net |
6.9 | 7.3 | (15.2 | ) | 8.8 | |||||||||||
Loss on extinguishment of debt |
(0.2 | ) | (14.6 | ) | (2.1 | ) | (15.1 | ) | ||||||||
Other income, net |
0.5 | 1.5 | 1.1 | 1.9 | ||||||||||||
Income (loss) before income tax expense (benefit) |
$ | 210.9 | $ | 0.8 | $ | 283.9 | $ | (19.3 | ) | |||||||
Income tax expense (benefit) |
76.7 | (0.4 | ) | 103.9 | (8.1 | ) | ||||||||||
Net income (loss) |
$ | 134.2 | $ | 1.2 | $ | 180.0 | $ | (11.2 | ) | |||||||
Net income (loss) attributable to noncontrolling
interest |
9.3 | — | 9.3 | — | ||||||||||||
Net income (loss) attributable to CVR Energy
stockholders |
$ | 124.9 | $ | 1.2 | $ | 170.7 | $ | (11.2 | ) | |||||||
* Amounts shown are exclusive of depreciation and amortization. |
||||||||||||||||
Basic earnings (loss) per share |
$ | 1.44 | $ | 0.01 | $ | 1.97 | $ | (0.13 | ) | |||||||
Diluted earnings (loss) per share |
$ | 1.42 | $ | 0.01 | $ | 1.94 | $ | (0.13 | ) | |||||||
Weighted average common shares outstanding |
||||||||||||||||
Basic |
86,422,881 | 86,336,125 | 86,418,356 | 86,332,700 | ||||||||||||
Diluted |
87,789,351 | 86,506,590 | 87,786,288 | 86,332,700 | ||||||||||||
| As of June 30, | As of December 31, | |||||||
| 2011 | 2010 | |||||||
| (in millions) | ||||||||
| (unaudited) | ||||||||
Balance Sheet Data: |
||||||||
Cash and cash equivalents |
$ | 748.0 | $ | 200.0 | ||||
Working capital |
951.4 | 333.6 | ||||||
Total assets |
2,349.9 | 1,740.2 | ||||||
Total debt, including current portion |
591.7 | 477.0 | ||||||
Total CVR stockholders’ equity |
973.4 | 689.6 | ||||||
Noncontrolling interest |
146.5 | 10.6 | ||||||
1
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Other Financial Data: |
||||||||||||||||
Cash flows provided by operating activities |
$ | 178.6 | $ | 2.2 | $ | 162.6 | $ | 45.7 | ||||||||
Cash flows used in investing activities |
(13.6 | ) | (5.4 | ) | (20.7 | ) | (16.8 | ) | ||||||||
Cash flows provided by (used in) financing
activities |
417.1 | 28.9 | 406.0 | (2.5 | ) | |||||||||||
Net cash flow |
$ | 582.1 | $ | 25.7 | $ | 547.9 | $ | 26.4 | ||||||||
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions except per share data) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Non-GAAP Measures: |
||||||||||||||||
Reconciliation of Net Income (loss)
to Adjusted Net Income (loss): |
||||||||||||||||
Net Income (loss) attributable to
CVR Energy stockholders |
$ | 124.9 | $ | 1.2 | $ | 170.7 | $ | (11.2 | ) | |||||||
Adjustments: |
||||||||||||||||
FIFO impact (favorable)
unfavorable, net of taxes (1) |
2.5 | 10.6 | (12.9 | ) | 3.1 | |||||||||||
Share-based compensation, net
of taxes (2) |
1.3 | (2.2 | ) | 15.0 | 3.6 | |||||||||||
Loss on extinguishment of debt,
net of taxes (3) |
0.1 | 8.7 | 1.3 | 9.1 | ||||||||||||
Major scheduled turnaround
expense, net of taxes (4) |
0.6 | 0.1 | 2.5 | 0.1 | ||||||||||||
Loss on disposition of fixed
assets, net of taxes (5) |
0.9 | 0.8 | 0.9 | 0.8 | ||||||||||||
Adjusted net income (6) |
$ | 130.3 | $ | 19.2 | $ | 177.5 | $ | 5.5 | ||||||||
Adjusted net income per diluted share |
$ | 1.48 | $ | 0.22 | $ | 2.02 | $ | 0.06 | ||||||||
2
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions, except operating statistics) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Petroleum Business Financial Results: |
||||||||||||||||
Net sales |
$ | 1,376.7 | $ | 951.3 | $ | 2,487.9 | $ | 1,808.0 | ||||||||
Cost of product sold* |
1,122.8 | 882.1 | 2,053.0 | 1,681.1 | ||||||||||||
Direct operating expenses * (7)(8) |
44.0 | 41.2 | 89.4 | 79.5 | ||||||||||||
Net costs associated with flood |
— | — | 0.1 | — | ||||||||||||
Depreciation and amortization |
17.0 | 16.4 | 33.9 | 32.6 | ||||||||||||
Gross profit (9) |
$ | 192.9 | $ | 11.6 | $ | 311.5 | $ | 14.8 | ||||||||
Plus direct operating expenses * |
44.0 | 41.2 | 89.4 | 79.5 | ||||||||||||
Plus net costs associated with flood |
— | — | 0.1 | — | ||||||||||||
Plus depreciation and amortization |
17.0 | 16.4 | 33.9 | 32.6 | ||||||||||||
Refining margin (10) |
$ | 253.9 | $ | 69.2 | $ | 434.9 | $ | 126.9 | ||||||||
FIFO impact (favorable) unfavorable (1) |
4.1 | 17.5 | (21.3 | ) | 5.2 | |||||||||||
Refining margin adjusted for FIFO impact (11) |
$ | 258.0 | $ | 86.7 | $ | 413.6 | $ | 132.1 | ||||||||
Operating income (loss) |
$ | 183.5 | $ | 4.6 | $ | 289.2 | $ | (2.4 | ) | |||||||
Adjusted Petroleum EBITDA (12) |
$ | 208.4 | $ | 46.5 | $ | 296.6 | $ | 45.5 | ||||||||
Petroleum Key Operating Statistics: |
||||||||||||||||
Per crude oil throughput barrel: |
||||||||||||||||
Refining margin (10) |
$ | 25.49 | $ | 6.70 | $ | 23.08 | $ | 6.41 | ||||||||
FIFO impact (favorable) unfavorable (1) |
0.41 | 1.70 | (1.13 | ) | 0.26 | |||||||||||
Refining margin adjusted for FIFO impact (11) |
25.90 | 8.40 | 21.95 | 6.67 | ||||||||||||
Gross profit (9) |
19.36 | 1.13 | 16.53 | 0.75 | ||||||||||||
Direct operating expenses * (7) |
4.42 | 3.99 | 4.74 | 4.02 | ||||||||||||
Direct operating expenses per barrel sold* (8) |
4.09 | 3.63 | 4.45 | 3.63 | ||||||||||||
Barrels sold (barrels per day) (8) |
118,435 | 124,486 | 110,860 | 121,016 | ||||||||||||
| * | Amounts shown are exclusive of depreciation and amortization |
3
| Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||
| June 30, | June 30, | |||||||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||||||||
Refining Throughput and
Production Data: |
||||||||||||||||||||||||||||||||
(barrels per day) |
||||||||||||||||||||||||||||||||
Throughput: |
||||||||||||||||||||||||||||||||
Sweet |
84,654 | 72.6 | % | 90,829 | 74.5 | % | 82,302 | 74.1 | % | 87,864 | 74.8 | % | ||||||||||||||||||||
Light/medium sour |
198 | 0.2 | % | 8,505 | 7.0 | % | 397 | 0.4 | % | 8,019 | 6.8 | % | ||||||||||||||||||||
Heavy sour |
24,634 | 21.2 | % | 14,097 | 11.6 | % | 21,416 | 19.3 | % | 13,425 | 11.4 | % | ||||||||||||||||||||
Total crude oil throughput |
109,486 | 94.0 | % | 113,431 | 93.1 | % | 104,115 | 93.8 | % | 109,308 | 93.0 | % | ||||||||||||||||||||
All other feedstocks and
blendstocks |
6,973 | 6.0 | % | 8,436 | 6.9 | % | 6,923 | 6.2 | % | 8,209 | 7.0 | % | ||||||||||||||||||||
Total throughput |
116,459 | 100.0 | % | 121,867 | 100.0 | % | 111,038 | 100.0 | % | 117,517 | 100.0 | % | ||||||||||||||||||||
Production: |
||||||||||||||||||||||||||||||||
Gasoline |
53,495 | 45.5 | % | 55,998 | 45.7 | % | 51,564 | 46.2 | % | 57,508 | 48.5 | % | ||||||||||||||||||||
Distillate |
48,959 | 41.6 | % | 51,008 | 41.6 | % | 45,934 | 41.1 | % | 48,137 | 40.6 | % | ||||||||||||||||||||
Other (excluding internally
produced fuel) |
15,106 | 12.9 | % | 15,607 | 12.7 | % | 14,158 | 12.7 | % | 12,911 | 10.9 | % | ||||||||||||||||||||
Total refining production
(excluding
internally produced fuel) |
117,560 | 100.0 | % | 122,613 | 100.0 | % | 111,656 | 100.0 | % | 118,556 | 100.0 | % | ||||||||||||||||||||
Product price (dollars per gallon): |
||||||||||||||||||||||||||||||||
Gasoline |
$ | 3.07 | $ | 2.12 | $ | 2.86 | $ | 2.08 | ||||||||||||||||||||||||
Distillate |
$ | 3.14 | $ | 2.17 | $ | 3.03 | $ | 2.12 | ||||||||||||||||||||||||
Market Indicators (dollars per
barrel): |
||||||||||||||||||||||||||||||||
West Texas Intermediate (WTI) NYMEX |
$ | 102.34 | $ | 78.05 | $ | 98.50 | $ | 78.46 | ||||||||||||||||||||||||
Crude Oil Differentials: |
||||||||||||||||||||||||||||||||
WTI less WTS (light/medium sour) |
2.51 | 1.84 | 3.30 | 1.86 | ||||||||||||||||||||||||||||
WTI less WCS (heavy sour) |
17.61 | 13.92 | 19.76 | 12.19 | ||||||||||||||||||||||||||||
NYMEX Crack Spreads: |
||||||||||||||||||||||||||||||||
Gasoline |
27.85 | 13.00 | 22.98 | 11.39 | ||||||||||||||||||||||||||||
Heating Oil |
25.56 | 10.50 | 24.76 | 8.89 | ||||||||||||||||||||||||||||
NYMEX 2-1-1 Crack Spread |
26.71 | 11.75 | 23.87 | 10.14 | ||||||||||||||||||||||||||||
PADD II Group 3 Basis: |
||||||||||||||||||||||||||||||||
Gasoline |
(1.59 | ) | (2.88 | ) | (1.82 | ) | (2.80 | ) | ||||||||||||||||||||||||
Ultra Low Sulfur Diesel |
3.24 | 2.58 | 2.21 | 1.13 | ||||||||||||||||||||||||||||
PADD II Group 3 Product Crack: |
||||||||||||||||||||||||||||||||
Gasoline |
26.26 | 10.12 | 21.16 | 8.58 | ||||||||||||||||||||||||||||
Ultra Low Sulfur Diesel |
28.81 | 13.08 | 26.97 | 10.03 | ||||||||||||||||||||||||||||
PADD II Group 3 2-1-1 |
27.53 | 11.60 | 24.06 | 9.31 | ||||||||||||||||||||||||||||
4
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions, except as noted) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Nitrogen Fertilizer Business Financial Results: |
||||||||||||||||
Net sales |
$ | 80.7 | $ | 56.3 | $ | 138.1 | $ | 94.6 | ||||||||
Cost of product sold* |
9.7 | 11.9 | 17.2 | 16.9 | ||||||||||||
Direct operating expenses * |
22.3 | 21.3 | 45.3 | 43.5 | ||||||||||||
Insurance recovery — business interruption |
— | — | (2.9 | ) | — | |||||||||||
Net cost associated with flood |
— | — | — | — | ||||||||||||
Depreciation and amortization |
4.7 | 4.7 | 9.3 | 9.3 | ||||||||||||
Operating income |
$ | 39.3 | $ | 16.5 | $ | 56.1 | $ | 19.5 | ||||||||
Adjusted Nitrogen Fertilizer EBITDA (12) |
$ | 45.0 | $ | 20.6 | $ | 70.9 | $ | 29.3 | ||||||||
Nitrogen Fertilizer Key Operating Statistics: |
||||||||||||||||
Production (thousand tons): |
||||||||||||||||
Ammonia (gross produced) (13) |
102.3 | 105.2 | 207.6 | 210.3 | ||||||||||||
Ammonia (net available for sale) (13) |
28.2 | 38.7 | 63.4 | 76.9 | ||||||||||||
UAN |
179.4 | 162.9 | 350.0 | 326.7 | ||||||||||||
Petroleum coke consumed (thousand tons) |
135.8 | 115.5 | 259.9 | 233.1 | ||||||||||||
Petroleum coke (cost per ton) |
$ | 30 | $ | 17 | $ | 23 | $ | 15 | ||||||||
Sales (thousand tons): |
||||||||||||||||
Ammonia |
33.6 | 50.6 | 60.9 | 81.8 | ||||||||||||
UAN |
166.1 | 172.2 | 345.4 | 327.9 | ||||||||||||
Total sales |
199.7 | 222.8 | 406.3 | 409.7 | ||||||||||||
Product pricing (plant gate) (dollars per ton) (14): |
||||||||||||||||
Ammonia |
$ | 574 | $ | 312 | $ | 570 | $ | 300 | ||||||||
UAN |
$ | 300 | $ | 205 | $ | 252 | $ | 187 | ||||||||
On-stream factors (15): |
||||||||||||||||
Gasification |
99.3 | % | 92.2 | % | 99.6 | % | 94.0 | % | ||||||||
Ammonia |
98.5 | % | 90.4 | % | 97.6 | % | 92.3 | % | ||||||||
UAN |
97.6 | % | 89.1 | % | 95.4 | % | 89.8 | % | ||||||||
Reconciliation to net sales (dollars in millions): |
||||||||||||||||
Freight in revenue |
$ | 5.4 | $ | 5.2 | $ | 10.2 | $ | 8.8 | ||||||||
Hydrogen revenue |
6.1 | — | 6.1 | — | ||||||||||||
Sales net plant gate |
69.2 | 51.1 | 121.8 | 85.8 | ||||||||||||
Total net sales |
$ | 80.7 | $ | 56.3 | $ | 138.1 | $ | 94.6 | ||||||||
Market Indicators: |
||||||||||||||||
Natural gas NYMEX (dollars per MMBtu) |
$ | 4.38 | $ | 4.35 | $ | 4.29 | $ | 4.67 | ||||||||
Ammonia — Southern Plains (dollars per ton) |
$ | 604 | $ | 359 | $ | 605 | $ | 345 | ||||||||
UAN — Mid Cornbelt (dollars per ton) |
$ | 366 | $ | 249 | $ | 358 | $ | 246 | ||||||||
| * | Amounts shown are exclusive of depreciation and amortization |
5
| (1) | First-in, first-out (“FIFO”) is the Company’s 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 is the gross and tax affected FIFO impact for the applicable periods: |
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Petroleum: |
||||||||||||||||
FIFO impact (favorable) unfavorable |
$ | 4.1 | $ | 17.5 | $ | (21.3 | ) | $ | 5.2 | |||||||
Income tax
expense (benefit) of FIFO |
(1.6 | ) | (6.9 | ) | 8.4 | (2.1 | ) | |||||||||
FIFO impact (favorable) unfavorable,
net of taxes |
$ | 2.5 | $ | 10.6 | $ | (12.9 | ) | $ | 3.1 | |||||||
| (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 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 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. 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 CVR Partners’ 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. |
6
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Share-based compensation recorded
in direct operating expenses: |
||||||||||||||||
Petroleum |
$ | 0.1 | $ | (0.1 | ) | $ | 0.8 | $ | 0.1 | |||||||
Nitrogen |
— | (0.1 | ) | 0.4 | 0.1 | |||||||||||
Corporate |
— | — | — | — | ||||||||||||
| $ | 0.1 | $ | (0.2 | ) | $ | 1.2 | $ | 0.2 | ||||||||
Share-based compensation recorded
in selling, general and administrative
expenses: |
||||||||||||||||
Petroleum |
$ | 0.4 | $ | (0.9 | ) | $ | 6.3 | $ | 1.1 | |||||||
Nitrogen |
0.9 | (0.4 | ) | 5.1 | 0.5 | |||||||||||
Corporate |
0.8 | (1.3 | ) | 8.7 | 2.6 | |||||||||||
| $ | 2.1 | $ | (2.6 | ) | $ | 20.1 | $ | 4.2 | ||||||||
Share-based compensation recorded
in other income |
(0.1 | ) | — | (0.1 | ) | — | ||||||||||
Total share-based compensation |
$ | 2.1 | $ | (2.8 | ) | $ | 21.2 | $ | 4.4 | |||||||
Income tax
expense (benefit) of share-based compensation |
(0.8 | ) | 0.6 | (6.2 | ) | (0.8 | ) | |||||||||
Share-based compensation, net of
taxes |
$ | 1.3 | $ | (2.2 | ) | $ | 15.0 | $ | 3.6 | |||||||
| (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 $0.2 million and was recognized as a loss on extinguishment of debt in our Consolidated Statement of Operations for the three months ended June 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 |
7
| in our Condensed Consolidated Statements of Operations. Below is the gross and tax affected loss on extinguishment of debt for the applicable periods: |
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Loss on extinguishment of debt |
$ | 0.2 | $ | 14.6 | $ | 2.1 | $ | 15.1 | ||||||||
Income tax benefit of loss on
extinguishment of debt |
(0.1 | ) | (5.9 | ) | (0.8 | ) | (6.0 | ) | ||||||||
Loss on extinguishment of debt, net of taxes |
$ | 0.1 | $ | 8.7 | $ | 1.3 | $ | 9.1 | ||||||||
| (4) | Represents expenses associated with a major scheduled turnaround for the refinery. |
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Major schedule turnaround expense |
$ | 1.1 | $ | 0.2 | $ | 4.3 | $ | 0.2 | ||||||||
Income tax benefit of turnaround
expense |
(0.5 | ) | (0.1 | ) | (1.8 | ) | (0.1 | ) | ||||||||
Major scheduled turnaround expense,
net of taxes |
$ | 0.6 | $ | 0.1 | $ | 2.5 | $ | 0.1 | ||||||||
| (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 is the gross and tax effected impacts for the applicable periods: |
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Loss on disposition of assets |
$ | 1.5 | $ | 1.3 | $ | 1.5 | $ | 1.3 | ||||||||
Income tax (benefit) of loss on
disposition of assets |
(0.6 | ) | (0.5 | ) | (0.6 | ) | (0.5 | ) | ||||||||
Loss on disposition of assets, net of taxes |
$ | 0.9 | $ | 0.8 | $ | 0.9 | $ | 0.8 | ||||||||
| (6) | 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 six months ended June 30, 2011 and 2010, these items included, on an after tax basis, the Company’s impact of the accounting for its inventory under FIFO, share-based compensation, loss on extinguishment of debt, major scheduled turnaround expenses and loss on disposition of fixed assets. 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
| (7) | 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. | |
| (8) | 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. | |
| (9) | 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. | |
| (10) | 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 refinery’s 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. | |
| (11) | 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 refinery’s 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. | |
| (12) | 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 six months ended June 30, 2011 and 2010: |
9
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Petroleum: |
||||||||||||||||
Petroleum operating income (loss) |
$ | 183.5 | $ | 4.6 | $ | 289.2 | $ | (2.4 | ) | |||||||
FIFO impacts (favorable), unfavorable |
4.1 | 17.5 | (21.3 | ) | 5.2 | |||||||||||
Share-based compensation |
0.5 | (1.0 | ) | 7.1 | 1.2 | |||||||||||
Major scheduled turnaround expenses |
1.1 | 0.2 | 4.3 | 0.2 | ||||||||||||
Realized gain (loss) on derivatives, net |
0.5 | 6.9 | (18.4 | ) | 6.9 | |||||||||||
Loss on disposition of fixed assets |
1.5 | 1.3 | 1.5 | 1.3 | ||||||||||||
Depreciation and amortization |
17.0 | 16.4 | 33.9 | 32.6 | ||||||||||||
Other income (expense) |
0.2 | 0.6 | 0.3 | 0.5 | ||||||||||||
Adjusted Petroleum EBITDA |
$ | 208.4 | $ | 46.5 | $ | 296.6 | $ | 45.5 | ||||||||
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in millions) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
Nitrogen Fertilizer: |
||||||||||||||||
Nitrogen Fertilizer operating income |
$ | 39.3 | $ | 16.5 | $ | 56.1 | $ | 19.5 | ||||||||
Share-based compensation |
0.9 | (0.5 | ) | 5.5 | 0.6 | |||||||||||
Major scheduled turnaround expenses |
— | — | — | — | ||||||||||||
Depreciation and amortization |
4.7 | 4.7 | 9.3 | 9.3 | ||||||||||||
Other income (expense) |
0.1 | (0.1 | ) | — | (0.1 | ) | ||||||||||
Adjusted Nitrogen Fertilizer EBITDA |
$ | 45.0 | $ | 20.6 | $ | 70.9 | $ | 29.3 | ||||||||
| (13) | 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. | |
| (14) | 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. | |
| (15) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. |
Use of Non-GAAP Financial Measures
To supplement the actual results in accordance with GAAP for the applicable periods, the
Company also uses non-GAAP measures as discussed above, which are adjusted for GAAP-based
results. The use of non-GAAP adjustments are not in accordance with or an alternative for
GAAP. The adjustments are provided to enhance an overall understanding of the Company’s
financial performance for the applicable periods and are indicators management believes are
relevant and useful for planning and forecasting future periods.
10