Delaware
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20-0467835
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(State or other jurisdiction
of incorporation or organization)
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(I.R.S. Employer
Identification No.)
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5320 Legacy Drive,
Plano, TX
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75024
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(Address of principal executive offices)
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(Zip Code)
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Registrant's telephone number, including area code:
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(972) 673-2000
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Large accelerated filer
þ
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Accelerated filer
o
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Non-accelerated filer
o
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Smaller reporting company
o
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(Do not check if a smaller reporting company)
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Class
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Outstanding at October 31, 2014
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Common Stock, $.001 par value
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352,562,628
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Page
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September 30,
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December 31,
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||||
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2014
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2013
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Assets
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Current assets
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Cash and cash equivalents
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$
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19,436
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$
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12,187
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Accrued production receivable
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261,482
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262,047
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Trade and other receivables, net
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85,386
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78,295
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Derivative assets
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29,862
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5
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Deferred tax assets
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6,127
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52,754
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Other current assets
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14,193
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9,271
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Total current assets
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416,486
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414,559
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Property and equipment
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Oil and natural gas properties (using full cost accounting)
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Proved properties
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9,575,271
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8,945,326
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Unevaluated properties
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856,184
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780,481
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CO
2
properties
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1,148,626
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1,117,167
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Pipelines and plants
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2,241,644
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2,209,560
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Other property and equipment
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468,846
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466,969
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Less accumulated depletion, depreciation, amortization and impairment
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(4,093,889
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)
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(3,668,225
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)
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Net property and equipment
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10,196,682
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9,851,278
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Derivative assets
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26,464
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9,942
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Goodwill
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1,283,590
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1,283,590
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Other assets
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216,831
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229,368
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Total assets
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$
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12,140,053
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$
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11,788,737
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Liabilities and Stockholders' Equity
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Current liabilities
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Accounts payable and accrued liabilities
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$
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366,153
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$
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410,543
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Oil and gas production payable
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157,452
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174,677
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Derivative liabilities
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534
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53,822
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Current maturities of long-term debt
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34,712
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36,157
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Total current liabilities
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558,851
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675,199
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Long-term liabilities
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Long-term debt, net of current portion
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3,560,214
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3,260,625
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Asset retirement obligations
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122,584
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119,888
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Derivative liabilities
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—
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3,413
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Deferred tax liabilities
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2,521,670
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2,399,294
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Other liabilities
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26,965
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28,912
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Total long-term liabilities
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6,231,433
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5,812,132
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Commitments and contingencies (Note 7)
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Stockholders' equity
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Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding
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—
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—
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Common stock, $.001 par value, 600,000,000 shares authorized; 411,367,190 and 409,215,573 shares issued, respectively
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411
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409
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Paid-in capital in excess of par
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3,225,323
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3,186,714
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Retained earnings
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3,050,743
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2,844,432
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Accumulated other comprehensive loss
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(226
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)
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(276
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)
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Treasury stock, at cost, 58,842,321 and 46,710,896 shares, respectively
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(926,482
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)
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(729,873
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)
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Total stockholders' equity
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5,349,769
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5,301,406
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Total liabilities and stockholders' equity
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$
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12,140,053
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$
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11,788,737
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Three Months Ended September 30,
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Nine Months Ended September 30,
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2014
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2013
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2014
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2013
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Revenues and other income
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Oil, natural gas, and related product sales
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$
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622,005
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$
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666,803
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$
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1,902,880
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$
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1,878,644
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CO
2
and helium sales and transportation fees
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11,378
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6,739
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33,961
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19,859
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Interest income and other income
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4,274
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11,293
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14,680
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19,502
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Total revenues and other income
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637,657
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684,835
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1,951,521
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1,918,005
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Expenses
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Lease operating expenses
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155,198
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180,967
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488,827
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542,067
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Marketing and plant operating expenses
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15,328
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13,131
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50,263
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36,259
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CO
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and helium discovery and operating expenses
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11,434
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4,120
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22,229
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11,261
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Taxes other than income
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39,966
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49,267
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136,761
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132,218
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General and administrative expenses
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40,366
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35,969
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123,011
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111,240
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Interest, net of amounts capitalized of $5,862, $19,768, $17,413, and $64,752, respectively
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44,752
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34,501
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140,136
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101,137
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Depletion, depreciation, and amortization
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146,560
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125,595
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435,854
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365,400
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Commodity derivatives expense (income)
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(252,265
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)
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80,446
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(825
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)
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46,874
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Loss on early extinguishment of debt
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—
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—
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113,908
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44,651
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Other expenses
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—
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1,474
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—
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14,292
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Total expenses
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201,339
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525,470
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1,510,164
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1,405,399
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Income before income taxes
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436,318
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159,365
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441,357
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512,606
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Income tax provision
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167,570
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57,311
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169,499
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193,001
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Net income
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$
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268,748
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$
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102,054
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$
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271,858
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$
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319,605
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Net income per common share
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Basic
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$
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0.77
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$
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0.28
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$
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0.78
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$
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0.87
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Diluted
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$
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0.77
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$
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0.28
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$
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0.77
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$
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0.86
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Dividends per common share
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$
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0.0625
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$
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—
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$
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0.1875
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$
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—
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Weighted average common shares outstanding
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Basic
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348,454
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366,088
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348,993
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368,101
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Diluted
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350,918
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369,142
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351,347
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371,316
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Three Months Ended September 30,
|
|
Nine Months Ended September 30,
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||||||||||||
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2014
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2013
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2014
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2013
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||||||||
Net income
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$
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268,748
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$
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102,054
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$
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271,858
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$
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319,605
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Other comprehensive income, net of income tax:
|
|
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Interest rate lock derivative contracts reclassified to income, net of tax of $11, $11, $35, and $30, respectively
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18
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17
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50
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54
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Total other comprehensive income
|
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18
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|
|
17
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|
50
|
|
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54
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||||
Comprehensive income
|
|
$
|
268,766
|
|
|
$
|
102,071
|
|
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$
|
271,908
|
|
|
$
|
319,659
|
|
|
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Nine Months Ended September 30,
|
||||||
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2014
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2013
|
||||
Cash flows from operating activities
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|
|
|
|
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Net income
|
|
$
|
271,858
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$
|
319,605
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Adjustments to reconcile net income to cash flow from operating activities
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|
|
|
|
|
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Depletion, depreciation, and amortization
|
|
435,854
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|
365,400
|
|
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Deferred income taxes
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|
168,967
|
|
|
169,634
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|
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Stock-based compensation
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26,104
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23,774
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|
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Commodity derivatives expense (income)
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(825
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)
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46,874
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Settlements of commodity derivatives
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(102,255
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)
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(662
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)
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Loss on early extinguishment of debt
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113,908
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44,651
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Amortization of debt issuance costs and discounts
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10,433
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10,581
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Other, net
|
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(5,037
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)
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(3,486
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)
|
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Changes in assets and liabilities, net of effects from acquisitions
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|
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Accrued production receivable
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565
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|
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(34,910
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)
|
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Trade and other receivables
|
|
(6,885
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)
|
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(756
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)
|
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Other current and long-term assets
|
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(370
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)
|
|
(1,199
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)
|
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Accounts payable and accrued liabilities
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(7,195
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)
|
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52,672
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|
||
Oil and natural gas production payable
|
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(17,225
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)
|
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31,111
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Other liabilities
|
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(2,800
|
)
|
|
(11,080
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)
|
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Net cash provided by operating activities
|
|
885,097
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1,012,209
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Cash flows from investing activities
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|
|
|
|
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|
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Oil and natural gas capital expenditures
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|
(699,012
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)
|
|
(688,270
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)
|
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CO
2
capital expenditures
|
|
(38,272
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)
|
|
(72,929
|
)
|
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Pipelines and plants capital expenditures
|
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(47,521
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)
|
|
(136,654
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)
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Purchases of other assets
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|
(6,253
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)
|
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(29,680
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)
|
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Net proceeds from sales of oil and natural gas properties and equipment
|
|
3,011
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|
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6,312
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|
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Other
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(876
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)
|
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(30,482
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)
|
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Net cash used in investing activities
|
|
(788,923
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)
|
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(951,703
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)
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|
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Cash flows from financing activities
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|
|
|
|
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|
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Bank repayments
|
|
(1,827,000
|
)
|
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(1,170,000
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)
|
||
Bank borrowings
|
|
1,897,000
|
|
|
780,000
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|
||
Repayment of senior subordinated notes
|
|
(997,345
|
)
|
|
(651,270
|
)
|
||
Premium paid on repayment of senior subordinated notes
|
|
(101,342
|
)
|
|
(36,475
|
)
|
||
Proceeds from issuance of senior subordinated notes
|
|
1,250,000
|
|
|
1,200,000
|
|
||
Costs of debt financing
|
|
(17,551
|
)
|
|
(20,026
|
)
|
||
Common stock repurchase program
|
|
(211,356
|
)
|
|
(215,197
|
)
|
||
Dividends paid
|
|
(65,241
|
)
|
|
—
|
|
||
Other
|
|
(16,090
|
)
|
|
(19,501
|
)
|
||
Net cash used in financing activities
|
|
(88,925
|
)
|
|
(132,469
|
)
|
||
Net increase (decrease) in cash and cash equivalents
|
|
7,249
|
|
|
(71,963
|
)
|
||
Cash and cash equivalents at beginning of period
|
|
12,187
|
|
|
98,511
|
|
||
Cash and cash equivalents at end of period
|
|
$
|
19,436
|
|
|
$
|
26,548
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||
|
|
September 30,
|
|
September 30,
|
||||||||
In thousands
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||
Basic weighted average common shares outstanding
|
|
348,454
|
|
|
366,088
|
|
|
348,993
|
|
|
368,101
|
|
Potentially dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock, stock options, SARs and performance-based equity awards
|
|
2,464
|
|
|
3,054
|
|
|
2,354
|
|
|
3,215
|
|
Diluted weighted average common shares outstanding
|
|
350,918
|
|
|
369,142
|
|
|
351,347
|
|
|
371,316
|
|
|
|
Nine Months Ended
|
||
In thousands, except per share data
|
|
September 30, 2013
|
||
Pro forma total revenues and other income
|
|
$
|
2,000,179
|
|
Pro forma net income
|
|
349,809
|
|
|
Pro forma net income per common share
|
|
|
||
Basic
|
|
$
|
0.95
|
|
Diluted
|
|
0.94
|
|
|
|
September 30,
|
|
December 31,
|
||||
In thousands
|
|
2014
|
|
2013
|
||||
Bank Credit Agreement
|
|
$
|
410,000
|
|
|
$
|
340,000
|
|
8¼% Senior Subordinated Notes due 2020
|
|
—
|
|
|
996,273
|
|
||
6⅜% Senior Subordinated Notes due 2021
|
|
400,000
|
|
|
400,000
|
|
||
5½% Senior Subordinated Notes due 2022
|
|
1,250,000
|
|
|
—
|
|
||
4⅝% Senior Subordinated Notes due 2023
|
|
1,200,000
|
|
|
1,200,000
|
|
||
Other Subordinated Notes, including premium of $13 and $16, respectively
|
|
2,747
|
|
|
3,823
|
|
||
Pipeline financings
|
|
222,585
|
|
|
228,167
|
|
||
Capital lease obligations
|
|
109,594
|
|
|
128,519
|
|
||
Total
|
|
3,594,926
|
|
|
3,296,782
|
|
||
Less: current obligations
|
|
(34,712
|
)
|
|
(36,157
|
)
|
||
Long-term debt and capital lease obligations
|
|
$
|
3,560,214
|
|
|
$
|
3,260,625
|
|
(1)
|
Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively.
|
(2)
|
Contract volumes are stated in Bbls/d and MMBtus/d for oil and natural gas contracts, respectively.
|
(3)
|
Ranges presented for fixed-price swaps and enhanced swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.
|
(4)
|
An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes, and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes.
|
(5)
|
A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes, and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.
|
•
|
Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.
|
•
|
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing. Our fixed-price swap contracts are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the written put features of our enhanced oil swaps and three-way collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
|
•
|
Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At
September 30, 2014
, instruments in this category include non-exchange-traded oil derivatives that are based on regional pricing other than NYMEX. The valuation models utilized for enhanced swaps, costless collars and three-way collars are consistent with the methodologies described above; however, since the instruments are based on regional pricing other than NYMEX, the inputs to the valuation are less observable. Implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. A one percent increase or decrease
|
|
|
Fair Value Measurements Using:
|
||||||||||||||
In thousands
|
|
Quoted Prices
in Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Total
|
||||||||
September 30, 2014
|
|
|
|
|
|
|
|
|
||||||||
Assets:
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas derivative contracts – current
|
|
$
|
—
|
|
|
$
|
18,609
|
|
|
$
|
11,253
|
|
|
$
|
29,862
|
|
Oil and natural gas derivative contracts – long-term
|
|
—
|
|
|
15,422
|
|
|
11,042
|
|
|
26,464
|
|
||||
Total Assets
|
|
$
|
—
|
|
|
$
|
34,031
|
|
|
$
|
22,295
|
|
|
$
|
56,326
|
|
|
|
|
|
|
|
|
|
|
||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil and natural gas derivative contracts – current
|
|
$
|
—
|
|
|
$
|
(534
|
)
|
|
$
|
—
|
|
|
$
|
(534
|
)
|
Oil and natural gas derivative contracts – long-term
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Total Liabilities
|
|
$
|
—
|
|
|
$
|
(534
|
)
|
|
$
|
—
|
|
|
$
|
(534
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil and natural gas derivative contracts – current
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
5
|
|
Oil and natural gas derivative contracts – long-term
|
|
—
|
|
|
3,034
|
|
|
6,908
|
|
|
9,942
|
|
||||
Total Assets
|
|
$
|
—
|
|
|
$
|
3,039
|
|
|
$
|
6,908
|
|
|
$
|
9,947
|
|
|
|
|
|
|
|
|
|
|
||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil and natural gas derivative contracts – current
|
|
$
|
—
|
|
|
$
|
(53,822
|
)
|
|
$
|
—
|
|
|
$
|
(53,822
|
)
|
Oil and natural gas derivative contracts – long-term
|
|
—
|
|
|
(3,214
|
)
|
|
(199
|
)
|
|
(3,413
|
)
|
||||
Total Liabilities
|
|
$
|
—
|
|
|
$
|
(57,036
|
)
|
|
$
|
(199
|
)
|
|
$
|
(57,235
|
)
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||||
In thousands
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Fair value of Level 3 instruments, beginning of period
|
|
$
|
(39,116
|
)
|
|
$
|
3,096
|
|
|
$
|
6,709
|
|
|
$
|
—
|
|
Fair value adjustments on commodity derivatives
|
|
61,411
|
|
|
(2,950
|
)
|
|
15,586
|
|
|
146
|
|
||||
Fair value of Level 3 instruments, end of period
|
|
$
|
22,295
|
|
|
$
|
146
|
|
|
$
|
22,295
|
|
|
$
|
146
|
|
|
|
|
|
|
|
|
|
|
||||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date
|
|
$
|
61,411
|
|
|
$
|
(2,950
|
)
|
|
$
|
15,586
|
|
|
$
|
146
|
|
|
|
Fair Value at
9/30/2014
(in thousands)
|
|
Valuation Technique
|
|
Unobservable Input
|
|
Range
|
||
Oil derivative contracts
|
|
$
|
22,295
|
|
|
Discounted cash flow / Black-Scholes
|
|
Volatility of Light Louisiana Sweet index for settlement periods beginning after January 1, 2015
|
|
14.7% – 23.8%
|
•
|
$680 million
allocated for tertiary oil field expenditures;
|
•
|
$220 million
allocated for other areas, primarily non-tertiary oil field expenditures;
|
•
|
$60 million
for pipeline construction;
|
•
|
$40 million
to be spent on CO
2
sources; and
|
•
|
$100 million
for other capital items such as capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.
|
|
|
Nine Months Ended
|
||||||
|
|
September 30,
|
||||||
In thousands
|
|
2014
|
|
2013
|
||||
Capital expenditures by project
|
|
|
|
|
||||
Tertiary oil fields
|
|
$
|
442,810
|
|
|
$
|
428,373
|
|
Non-tertiary fields
|
|
186,708
|
|
|
136,796
|
|
||
Capitalized interest and internal costs
(1)
|
|
67,437
|
|
|
89,200
|
|
||
Oil and natural gas capital expenditures
|
|
696,955
|
|
|
654,369
|
|
||
CO
2
pipelines
|
|
24,612
|
|
|
39,363
|
|
||
CO
2
sources
(2)
|
|
37,502
|
|
|
114,240
|
|
||
CO
2
capitalized interest and other
|
|
2,831
|
|
|
35,200
|
|
||
Capital expenditures, before acquisitions
|
|
761,900
|
|
|
843,172
|
|
||
Property acquisitions
(3)
|
|
1,683
|
|
|
1,062,607
|
|
||
Capital expenditures, total
|
|
$
|
763,583
|
|
|
$
|
1,905,779
|
|
(1)
|
Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.
|
(2)
|
Includes capital expenditures related to the Riley Ridge gas processing facility.
|
(3)
|
Property acquisitions during the
nine months ended
September 30, 2013 include capital expenditures of approximately $
1.1 billion
related to acquisitions during that period that are not reflected as an Investing Activity on our Unaudited Condensed Consolidated Statements of Cash Flows due to the movement of proceeds through a qualified intermediary to facilitate like-kind-exchange treatment under federal income tax rules.
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||||
In thousands, except per share and unit data
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Operating results
|
|
|
|
|
|
|
|
|
||||||||
Net income
|
|
$
|
268,748
|
|
|
$
|
102,054
|
|
|
$
|
271,858
|
|
|
$
|
319,605
|
|
Net income per common share – basic
|
|
0.77
|
|
|
0.28
|
|
|
0.78
|
|
|
0.87
|
|
||||
Net income per common share – diluted
|
|
0.77
|
|
|
0.28
|
|
|
0.77
|
|
|
0.86
|
|
||||
Net cash provided by operating activities
|
|
340,392
|
|
|
305,465
|
|
|
885,097
|
|
|
1,012,209
|
|
||||
Average daily production volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Bbls/d
|
|
70,619
|
|
|
67,705
|
|
|
70,504
|
|
|
65,755
|
|
||||
Mcf/d
|
|
19,147
|
|
|
22,957
|
|
|
22,671
|
|
|
24,451
|
|
||||
BOE/d
(1)
|
|
73,810
|
|
|
71,531
|
|
|
74,283
|
|
|
69,830
|
|
||||
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil sales
|
|
$
|
615,745
|
|
|
$
|
659,674
|
|
|
$
|
1,876,524
|
|
|
$
|
1,855,006
|
|
Natural gas sales
|
|
6,260
|
|
|
7,129
|
|
|
26,356
|
|
|
23,638
|
|
||||
Total oil and natural gas sales
|
|
$
|
622,005
|
|
|
$
|
666,803
|
|
|
$
|
1,902,880
|
|
|
$
|
1,878,644
|
|
Commodity derivative contracts
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Payment on settlements of commodity derivatives
|
|
$
|
(24,914
|
)
|
|
$
|
(662
|
)
|
|
$
|
(102,255
|
)
|
|
$
|
(662
|
)
|
Noncash fair value adjustments on commodity derivatives
(3)
|
|
277,179
|
|
|
(79,784
|
)
|
|
103,080
|
|
|
(46,212
|
)
|
||||
Commodity derivatives income (expense)
|
|
$
|
252,265
|
|
|
$
|
(80,446
|
)
|
|
$
|
825
|
|
|
$
|
(46,874
|
)
|
Unit prices – excluding impact of derivative settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil price per Bbl
|
|
$
|
94.78
|
|
|
$
|
105.91
|
|
|
$
|
97.49
|
|
|
$
|
103.34
|
|
Natural gas price per Mcf
|
|
3.55
|
|
|
3.38
|
|
|
4.26
|
|
|
3.54
|
|
||||
Unit prices – including impact of derivative settlements
(2)
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil price per Bbl
|
|
$
|
90.92
|
|
|
$
|
105.80
|
|
|
$
|
92.22
|
|
|
$
|
103.30
|
|
Natural gas price per Mcf
|
|
3.61
|
|
|
3.38
|
|
|
4.13
|
|
|
3.54
|
|
||||
Oil and natural gas operating expenses
|
|
|
|
|
|
|
|
|
|
|
||||||
Lease operating expenses
(4)
|
|
$
|
155,198
|
|
|
$
|
180,967
|
|
|
$
|
488,827
|
|
|
$
|
542,067
|
|
Marketing expenses, net of third-party purchases, and plant operating expenses
|
|
11,082
|
|
|
9,123
|
|
|
36,869
|
|
|
27,647
|
|
||||
Production and ad valorem taxes
|
|
36,279
|
|
|
46,073
|
|
|
126,213
|
|
|
122,542
|
|
||||
Oil and natural gas operating revenues and expenses per BOE
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil and natural gas revenues
|
|
$
|
91.60
|
|
|
$
|
101.32
|
|
|
$
|
93.83
|
|
|
$
|
98.55
|
|
Lease operating expenses
(4)
|
|
22.86
|
|
|
27.50
|
|
|
24.10
|
|
|
28.43
|
|
||||
Marketing expenses, net of third-party purchases, and plant operating expenses
|
|
1.63
|
|
|
1.39
|
|
|
1.82
|
|
|
1.45
|
|
||||
Production and ad valorem taxes
|
|
5.34
|
|
|
7.00
|
|
|
6.22
|
|
|
6.43
|
|
||||
CO
2
sources and helium – revenues and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
CO
2
and helium sales and transportation fees
|
|
$
|
11,378
|
|
|
$
|
6,739
|
|
|
$
|
33,961
|
|
|
$
|
19,859
|
|
CO
2
and helium discovery and operating expenses
|
|
(11,434
|
)
|
|
(4,120
|
)
|
|
(22,229
|
)
|
|
(11,261
|
)
|
||||
CO
2
and helium revenue and expenses, net
|
|
$
|
(56
|
)
|
|
$
|
2,619
|
|
|
$
|
11,732
|
|
|
$
|
8,598
|
|
(1)
|
Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE").
|
(2)
|
See also
Commodity Derivative Contracts
below and
Item 3. Quantitative and Qualitative Disclosures about Market Risk
for information concerning our derivative transactions.
|
(3)
|
Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from "Commodity derivatives expense (income)" in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value adjustments on commodity derivatives represents only the net change between periods of the fair market values of commodity derivative positions, and excludes the impact of settlements on commodity derivatives during the period, which were
payments
on settlements of
$24.9 million
and
$102.3 million
for the
three and nine months ended
September 30, 2014
, respectively, and payments on settlements of
$0.7 million
for the
three and nine months ended
September 30, 2013
. We believe that noncash fair value adjustments on commodity derivatives is a useful supplemental disclosure to "Commodity derivatives expense (income)" in order to differentiate noncash fair market value adjustments from settlements on commodity derivatives during the period. This supplemental disclosure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for "Commodity derivatives expense (income)" in the Unaudited Condensed Consolidated Statements of Operations.
|
(4)
|
If lease operating expenses and related insurance recoveries recorded to remediate an area of Delhi Field (see
Capital Resources and Liquidity
–
Insurance Recoveries to Cover Costs of 2013 Delhi Field Release
above) were excluded, lease operating expenses would have totaled
$165.1 million
and
$498.7 million
for the
three and nine months ended
September 30, 2014
, respectively, and
$153.0 million
and
$444.1 million
for the
three and nine months ended
September 30, 2013
, respectively. Lease operating expense per BOE would have averaged
$24.32
and
$24.59
for the
three and nine months ended
September 30, 2014
, respectively, and
$23.24
and
$23.29
for the
three and nine months ended
September 30, 2013
, respectively.
|
|
|
Average Daily Production (BOE/d)
|
||||||||||||||||||||
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|||||||
Operating Area
|
|
2013
|
|
2013
|
|
2013
|
|
2013
|
|
|
2014
|
|
2014
|
|
2014
|
|||||||
Tertiary oil production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Gulf Coast region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Mature properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Brookhaven
|
|
2,305
|
|
|
2,339
|
|
|
2,224
|
|
|
2,026
|
|
|
|
1,877
|
|
|
1,818
|
|
|
1,767
|
|
Eucutta
|
|
2,636
|
|
|
2,642
|
|
|
2,504
|
|
|
2,280
|
|
|
|
2,181
|
|
|
2,150
|
|
|
2,224
|
|
Mallalieu
|
|
2,116
|
|
|
2,157
|
|
|
2,042
|
|
|
1,886
|
|
|
|
1,837
|
|
|
1,839
|
|
|
1,869
|
|
Other mature properties
(1)
|
|
7,800
|
|
|
7,233
|
|
|
6,761
|
|
|
6,287
|
|
|
|
6,283
|
|
|
6,156
|
|
|
6,189
|
|
Total mature properties
|
|
14,857
|
|
|
14,371
|
|
|
13,531
|
|
|
12,479
|
|
|
|
12,178
|
|
|
11,963
|
|
|
12,049
|
|
Delhi
|
|
5,827
|
|
|
5,479
|
|
|
4,517
|
|
|
4,793
|
|
|
|
4,708
|
|
|
4,543
|
|
|
4,377
|
|
Hastings
|
|
3,956
|
|
|
4,010
|
|
|
3,699
|
|
|
4,270
|
|
|
|
4,618
|
|
|
4,759
|
|
|
4,917
|
|
Heidelberg
|
|
3,943
|
|
|
4,149
|
|
|
4,553
|
|
|
5,206
|
|
|
|
5,325
|
|
|
5,609
|
|
|
5,721
|
|
Oyster Bayou
|
|
2,252
|
|
|
2,518
|
|
|
3,213
|
|
|
3,869
|
|
|
|
4,055
|
|
|
4,415
|
|
|
4,605
|
|
Tinsley
|
|
8,222
|
|
|
8,225
|
|
|
7,951
|
|
|
7,809
|
|
|
|
8,430
|
|
|
8,518
|
|
|
8,310
|
|
Total Gulf Coast region
|
|
39,057
|
|
|
38,752
|
|
|
37,464
|
|
|
38,426
|
|
|
|
39,314
|
|
|
39,807
|
|
|
39,979
|
|
Rocky Mountain region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Bell Creek
|
|
—
|
|
|
—
|
|
|
49
|
|
|
177
|
|
|
|
578
|
|
|
1,090
|
|
|
1,648
|
|
Total Rocky Mountain region
|
|
—
|
|
|
—
|
|
|
49
|
|
|
177
|
|
|
|
578
|
|
|
1,090
|
|
|
1,648
|
|
Total tertiary oil production
|
|
39,057
|
|
|
38,752
|
|
|
37,513
|
|
|
38,603
|
|
|
|
39,892
|
|
|
40,897
|
|
|
41,627
|
|
Non-tertiary oil and gas production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Gulf Coast region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Mississippi
|
|
3,013
|
|
|
2,367
|
|
|
2,692
|
|
|
2,711
|
|
|
|
2,513
|
|
|
2,319
|
|
|
2,346
|
|
Texas
|
|
6,692
|
|
|
6,932
|
|
|
6,548
|
|
|
5,994
|
|
|
|
6,444
|
|
|
6,508
|
|
|
5,537
|
|
Other
|
|
1,153
|
|
|
1,108
|
|
|
1,087
|
|
|
1,041
|
|
|
|
1,031
|
|
|
1,049
|
|
|
1,083
|
|
Total Gulf Coast region
|
|
10,858
|
|
|
10,407
|
|
|
10,327
|
|
|
9,746
|
|
|
|
9,988
|
|
|
9,876
|
|
|
8,966
|
|
Rocky Mountain region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Cedar Creek Anticline
(2)
|
|
8,745
|
|
|
19,935
|
|
|
18,872
|
|
|
18,601
|
|
|
|
19,007
|
|
|
19,155
|
|
|
18,623
|
|
Other
|
|
5,163
|
|
|
4,958
|
|
|
4,819
|
|
|
4,516
|
|
|
|
4,831
|
|
|
5,392
|
|
|
4,594
|
|
Total Rocky Mountain region
|
|
13,908
|
|
|
24,893
|
|
|
23,691
|
|
|
23,117
|
|
|
|
23,838
|
|
|
24,547
|
|
|
23,217
|
|
Total non-tertiary production
|
|
24,766
|
|
|
35,300
|
|
|
34,018
|
|
|
32,863
|
|
|
|
33,826
|
|
|
34,423
|
|
|
32,183
|
|
Total production
|
|
63,823
|
|
|
74,052
|
|
|
71,531
|
|
|
71,466
|
|
|
|
73,718
|
|
|
75,320
|
|
|
73,810
|
|
(1)
|
Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.
|
(2)
|
Beginning March 27, 2013, amounts include production from our purchase of additional interests in Cedar Creek Anticline ("CCA") on that date.
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||
|
|
2014 vs. 2013
|
|
2014 vs. 2013
|
||||||||||
In thousands
|
|
Increase (Decrease) in Revenues
|
|
Percentage Increase (Decrease) in Revenues
|
|
Increase (Decrease) in Revenues
|
|
Percentage Increase (Decrease) in Revenues
|
||||||
Change in oil and natural gas revenues due to:
|
|
|
|
|
|
|
|
|
||||||
Increase in production
|
|
$
|
21,240
|
|
|
3
|
%
|
|
$
|
119,784
|
|
|
6
|
%
|
Decrease in commodity prices
|
|
(66,038
|
)
|
|
(10
|
)%
|
|
(95,548
|
)
|
|
(5
|
)%
|
||
Total increase (decrease) in oil and natural gas revenues
|
|
$
|
(44,798
|
)
|
|
(7
|
)%
|
|
$
|
24,236
|
|
|
1
|
%
|
|
|
Three Months Ended
|
|
Three Months Ended
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
September 30,
|
||||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||||||||||
Net realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Oil price per Bbl
|
|
$
|
97.69
|
|
|
$
|
105.59
|
|
|
$
|
100.04
|
|
|
$
|
98.92
|
|
|
$
|
94.78
|
|
|
$
|
105.91
|
|
|
$
|
97.49
|
|
|
$
|
103.34
|
|
Natural gas price per Mcf
|
|
4.71
|
|
|
3.28
|
|
|
4.39
|
|
|
3.96
|
|
|
3.55
|
|
|
3.38
|
|
|
4.26
|
|
|
3.54
|
|
||||||||
Price per BOE
|
|
94.03
|
|
|
99.87
|
|
|
95.86
|
|
|
94.70
|
|
|
91.60
|
|
|
101.32
|
|
|
93.83
|
|
|
98.55
|
|
||||||||
NYMEX differentials:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Oil per Bbl
|
|
$
|
(0.91
|
)
|
|
$
|
11.17
|
|
|
$
|
(3.03
|
)
|
|
$
|
4.78
|
|
|
$
|
(2.53
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(2.16
|
)
|
|
$
|
5.13
|
|
Natural gas per Mcf
|
|
(0.02
|
)
|
|
(0.21
|
)
|
|
(0.19
|
)
|
|
(0.05
|
)
|
|
(0.40
|
)
|
|
(0.18
|
)
|
|
(0.16
|
)
|
|
(0.15
|
)
|
(1)
|
Noncash fair value adjustments on commodity derivatives is a non-GAAP measure. See
Operating Results Table
above for a discussion of the reconciliation between noncash fair value adjustments on commodity derivatives to "Commodity derivatives expense (income)" in the Unaudited Condensed Consolidated Statements of Operations.
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||||
In thousands, except per-BOE data
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Lease operating expense
|
|
|
|
|
|
|
|
|
||||||||
Tertiary – excluding Delhi remediation
|
|
$
|
95,671
|
|
|
$
|
86,534
|
|
|
$
|
292,238
|
|
|
$
|
256,283
|
|
Tertiary – Delhi remediation
|
|
(9,906
|
)
|
|
28,000
|
|
|
(9,906
|
)
|
|
98,000
|
|
||||
Non-tertiary
|
|
69,433
|
|
|
66,433
|
|
|
206,495
|
|
|
187,784
|
|
||||
Total lease operating expense
|
|
$
|
155,198
|
|
|
$
|
180,967
|
|
|
$
|
488,827
|
|
|
$
|
542,067
|
|
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expense per BOE
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Tertiary – excluding Delhi remediation
|
|
$
|
24.98
|
|
|
$
|
25.08
|
|
|
$
|
26.23
|
|
|
$
|
24.42
|
|
Tertiary – Delhi remediation
|
|
(2.58
|
)
|
|
8.11
|
|
|
(0.89
|
)
|
|
9.34
|
|
||||
Non-tertiary
|
|
23.45
|
|
|
21.23
|
|
|
22.60
|
|
|
21.91
|
|
||||
Total lease operating expense per BOE
|
|
22.86
|
|
|
27.50
|
|
|
24.10
|
|
|
28.43
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||||
In thousands, except per-BOE data and employees
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Gross cash compensation and administrative costs
|
|
$
|
87,355
|
|
|
$
|
82,653
|
|
|
$
|
265,400
|
|
|
$
|
247,171
|
|
Gross stock-based compensation
|
|
10,986
|
|
|
10,032
|
|
|
33,343
|
|
|
30,791
|
|
||||
Operator labor and overhead recovery charges
|
|
(42,763
|
)
|
|
(43,272
|
)
|
|
(128,836
|
)
|
|
(125,064
|
)
|
||||
Capitalized exploration and development costs
|
|
(15,212
|
)
|
|
(13,444
|
)
|
|
(46,896
|
)
|
|
(41,658
|
)
|
||||
Net G&A expense
|
|
$
|
40,366
|
|
|
$
|
35,969
|
|
|
$
|
123,011
|
|
|
$
|
111,240
|
|
|
|
|
|
|
|
|
|
|
||||||||
G&A per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net administrative costs
|
|
$
|
4.72
|
|
|
$
|
4.32
|
|
|
$
|
4.88
|
|
|
$
|
4.69
|
|
Net stock-based compensation
|
|
1.22
|
|
|
1.15
|
|
|
1.19
|
|
|
1.15
|
|
||||
Net G&A expense
|
|
$
|
5.94
|
|
|
$
|
5.47
|
|
|
$
|
6.07
|
|
|
$
|
5.84
|
|
|
|
|
|
|
|
|
|
|
||||||||
Employees as of September 30
|
|
1,502
|
|
|
1,494
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||||
In thousands, except per-BOE data and interest rates
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Cash interest expense
|
|
$
|
47,158
|
|
|
$
|
50,828
|
|
|
$
|
147,115
|
|
|
$
|
155,308
|
|
Noncash interest expense
|
|
3,456
|
|
|
3,441
|
|
|
10,434
|
|
|
10,581
|
|
||||
Less: capitalized interest
|
|
(5,862
|
)
|
|
(19,768
|
)
|
|
(17,413
|
)
|
|
(64,752
|
)
|
||||
Interest expense, net
|
|
$
|
44,752
|
|
|
$
|
34,501
|
|
|
$
|
140,136
|
|
|
$
|
101,137
|
|
Interest expense, net per BOE
|
|
$
|
6.59
|
|
|
$
|
5.24
|
|
|
$
|
6.91
|
|
|
$
|
5.31
|
|
Average debt outstanding
|
|
$
|
3,622,579
|
|
|
$
|
3,278,972
|
|
|
$
|
3,618,149
|
|
|
$
|
3,260,030
|
|
Average interest rate
(1)
|
|
5.2
|
%
|
|
6.2
|
%
|
|
5.4
|
%
|
|
6.4
|
%
|
(1)
|
Includes commitment fees but excludes debt issue costs and amortization of discount or premium.
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||||
In thousands, except per-BOE data
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Depletion and depreciation of oil and natural gas properties
|
|
$
|
114,224
|
|
|
$
|
98,473
|
|
|
$
|
337,841
|
|
|
$
|
283,579
|
|
Depletion and depreciation of CO
2
properties
|
|
7,041
|
|
|
6,603
|
|
|
22,341
|
|
|
20,872
|
|
||||
Asset retirement obligations
|
|
2,207
|
|
|
2,117
|
|
|
6,605
|
|
|
6,337
|
|
||||
Depreciation of pipelines, plants and other property and equipment
|
|
23,088
|
|
|
18,402
|
|
|
69,067
|
|
|
54,612
|
|
||||
Total DD&A
|
|
$
|
146,560
|
|
|
$
|
125,595
|
|
|
$
|
435,854
|
|
|
$
|
365,400
|
|
|
|
|
|
|
|
|
|
|
||||||||
DD&A per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil and natural gas properties
|
|
$
|
17.15
|
|
|
$
|
15.28
|
|
|
$
|
16.99
|
|
|
$
|
15.21
|
|
CO
2
, pipelines, plants and other property and equipment
|
|
4.43
|
|
|
3.80
|
|
|
4.50
|
|
|
3.96
|
|
||||
Total DD&A cost per BOE
|
|
$
|
21.58
|
|
|
$
|
19.08
|
|
|
$
|
21.49
|
|
|
$
|
19.17
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||||
In thousands, except per-BOE amounts and tax rates
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Current income tax expense
|
|
$
|
214
|
|
|
$
|
16,019
|
|
|
$
|
532
|
|
|
$
|
23,367
|
|
Deferred income tax expense
|
|
167,356
|
|
|
41,292
|
|
|
168,967
|
|
|
169,634
|
|
||||
Total income tax expense
|
|
$
|
167,570
|
|
|
$
|
57,311
|
|
|
$
|
169,499
|
|
|
$
|
193,001
|
|
Average income tax expense per BOE
|
|
$
|
24.68
|
|
|
$
|
8.71
|
|
|
$
|
8.36
|
|
|
$
|
10.12
|
|
Effective tax rate
|
|
38.4
|
%
|
|
36.0
|
%
|
|
38.4
|
%
|
|
37.7
|
%
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
|
September 30,
|
|
September 30,
|
||||||||||||
Per-BOE data
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Oil and natural gas revenues
|
|
$
|
91.60
|
|
|
$
|
101.32
|
|
|
$
|
93.83
|
|
|
$
|
98.55
|
|
Payment on settlements of commodity derivatives
|
|
(3.67
|
)
|
|
(0.10
|
)
|
|
(5.04
|
)
|
|
(0.03
|
)
|
||||
Lease operating expenses – excluding Delhi Field remediation
|
|
(24.32
|
)
|
|
(23.24
|
)
|
|
(24.59
|
)
|
|
(23.29
|
)
|
||||
Lease operating expenses – Delhi Field remediation
|
|
1.46
|
|
|
(4.26
|
)
|
|
0.49
|
|
|
(5.14
|
)
|
||||
Production and ad valorem taxes
|
|
(5.34
|
)
|
|
(7.00
|
)
|
|
(6.22
|
)
|
|
(6.43
|
)
|
||||
Marketing expenses, net of third-party purchases, and plant operating expenses
|
|
(1.63
|
)
|
|
(1.39
|
)
|
|
(1.82
|
)
|
|
(1.45
|
)
|
||||
Production netback
|
|
58.10
|
|
|
65.33
|
|
|
56.65
|
|
|
62.21
|
|
||||
CO
2
and helium sales, net of operating and exploration expenses
|
|
—
|
|
|
0.39
|
|
|
0.57
|
|
|
0.45
|
|
||||
General and administrative expenses
|
|
(5.94
|
)
|
|
(5.47
|
)
|
|
(6.07
|
)
|
|
(5.84
|
)
|
||||
Interest expense, net
|
|
(6.59
|
)
|
|
(5.24
|
)
|
|
(6.91
|
)
|
|
(5.31
|
)
|
||||
Other
|
|
1.00
|
|
|
(1.57
|
)
|
|
1.08
|
|
|
(0.29
|
)
|
||||
Changes in assets and liabilities relating to operations
|
|
3.56
|
|
|
(7.02
|
)
|
|
(1.67
|
)
|
|
1.88
|
|
||||
Cash flow from operations
|
|
50.13
|
|
|
46.42
|
|
|
43.65
|
|
|
53.10
|
|
||||
DD&A
|
|
(21.58
|
)
|
|
(19.08
|
)
|
|
(21.49
|
)
|
|
(19.17
|
)
|
||||
Deferred income taxes
|
|
(24.65
|
)
|
|
(6.28
|
)
|
|
(8.33
|
)
|
|
(8.89
|
)
|
||||
Loss on early extinguishment of debt
|
|
—
|
|
|
—
|
|
|
(5.62
|
)
|
|
(2.34
|
)
|
||||
Noncash fair value adjustments on commodity derivatives
|
|
40.82
|
|
|
(12.12
|
)
|
|
5.08
|
|
|
(2.42
|
)
|
||||
Other noncash items
|
|
(5.14
|
)
|
|
6.57
|
|
|
0.12
|
|
|
(3.51
|
)
|
||||
Net income
|
|
$
|
39.58
|
|
|
$
|
15.51
|
|
|
$
|
13.41
|
|
|
$
|
16.77
|
|
In thousands
|
|
2015
|
|
2016
|
|
2017
|
|
2021
|
|
2022
|
|
2023
|
|
Total
|
||||||||||||||
Variable rate debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Bank Credit Facility (weighted average interest rate of 1.9% at September 30, 2014)
|
|
$
|
—
|
|
|
$
|
410,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
410,000
|
|
Fixed rate debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
6
⅜
% Senior Subordinated Notes due 2021
|
|
—
|
|
|
—
|
|
|
—
|
|
|
400,000
|
|
|
—
|
|
|
—
|
|
|
400,000
|
|
|||||||
5½% Senior Subordinated Notes due 2022
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,250,000
|
|
|
—
|
|
|
1,250,000
|
|
|||||||
4
⅝
% Senior Subordinated Notes due 2023
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,200,000
|
|
|
1,200,000
|
|
|||||||
Other Subordinated Notes
|
|
484
|
|
|
—
|
|
|
2,250
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,734
|
|
|
|
Receipt / (Payment)
|
||||||
In thousands
|
|
Crude Oil Derivative Contracts
|
|
Natural Gas Derivative Contracts
|
||||
Based on:
|
|
|
|
|
||||
Futures prices as of September 30, 2014
|
|
$
|
50,230
|
|
|
$
|
265
|
|
10% increase in prices
|
|
(128,835
|
)
|
|
(350
|
)
|
||
10% decrease in prices
|
|
250,479
|
|
|
1,940
|
|
Month
|
|
Total Number of Shares Purchased
(1)
|
|
Average Price Paid per Share
|
|
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or Programs
|
|
Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under the Plans or Programs
(in millions)
(2)
|
||||||
July 2014
|
|
23,243
|
|
|
$
|
17.93
|
|
|
—
|
|
|
$
|
221.9
|
|
August 2014
|
|
11,225
|
|
|
16.74
|
|
|
—
|
|
|
221.9
|
|
||
September 2014
|
|
5,997
|
|
|
15.97
|
|
|
—
|
|
|
221.9
|
|
||
Total
|
|
40,465
|
|
|
|
|
—
|
|
|
|
|
(1)
|
Stock repurchases during the
third quarter
of
2014
were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights.
|
(2)
|
In October 2011, our Board of Directors approved a common stock repurchase program for up to $500 million of Denbury's common stock, which was increased by an additional $271.2 million in November 2012, $140.7 million in November 2013, and $250.0 million in December 2013, for a total authorization under the program of $1.162 billion. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.
|
Exhibit No.
|
|
Exhibit
|
3(a)*
|
|
Second Restated Certificate of Incorporation of Denbury Resources Inc. filed with the Delaware Secretary of State on October 30, 2014.
|
3(b)*
|
|
Second Amended and Restated Bylaws of Denbury Resources Inc. dated as of November 4, 2014.
|
4(a)
|
|
Indenture for 5½% Senior Subordinated Notes due 2022, dated as of April 30, 2014, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on May 1, 2014, File No. 001-12935).
|
4(b)
|
|
Third Supplemental Indenture for 8¼% Senior Subordinated Notes due 2020, dated as of April 30, 2014, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 of Form 8-K filed by the Company on May 1, 2014, File No. 001-12935).
|
31(a)*
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
31(b)*
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32*
|
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
101*
|
|
Interactive Data Files.
|
*
|
Included herewith.
|
|
|
DENBURY RESOURCES INC.
|
|
|
|
November 7, 2014
|
|
/s/ Mark C. Allen
|
|
|
Mark C. Allen
Sr. Vice President and Chief Financial Officer
|
|
|
|
November 7, 2014
|
|
/s/ Alan Rhoades
|
|
|
Alan Rhoades
Vice President and Chief Accounting Officer
|
Exhibit No.
|
|
Exhibit
|
3(a)
|
|
Second Restated Certificate of Incorporation of Denbury Resources Inc. filed with the Delaware Secretary of State on October 30, 2014.
|
3(b)
|
|
Second Amended and Restated Bylaws of Denbury Resources Inc. dated as of November 4, 2014.
|
31(a)
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
31(b)
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32
|
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
101
|
|
Interactive Data Files.
|
|
|
Amended and Restated as of
|
|
|
|
|
|
November 4, 2014
|
|
|
|
|
|
/s/ James S. Matthews
|
|
|
James S. Matthews, Secretary
|
1.
|
I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
November 7, 2014
|
|
/s/ Phil Rykhoek
|
|
|
Phil Rykhoek
|
|
|
President and Chief Executive Officer
|
1.
|
I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
November 7, 2014
|
|
/s/ Mark Allen
|
|
|
Mark C. Allen
|
|
|
Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
2.
|
The Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury.
|
Dated:
|
November 7, 2014
|
|
/s/ Phil Rykhoek
|
|
|
|
Phil Rykhoek
|
|
|
|
President and Chief Executive Officer
|
|
|
|
|
|
|
|
|
Dated:
|
November 7, 2014
|
|
/s/ Mark C. Allen
|
|
|
|
Mark C. Allen
|
|
|
|
Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary
|