CIMAREX ENERGY CO.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
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Retained
Earnings (Accumulated Deficit)
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Accumulated
Other Comprehensive Income (Loss)
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Total Stockholders’ Equity
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Common Stock
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Additional Paid-in Capital
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Shares
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Amount
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Balance, December 31, 2014
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87,592
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$
|
876
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|
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$
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1,997,080
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$
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2,332,909
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|
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$
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1,102
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$
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4,331,967
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Dividends paid on stock awards subsequently forfeited
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—
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—
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|
|
—
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|
|
109
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—
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109
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Dividends
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—
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—
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—
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(59,422
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)
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—
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(59,422
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)
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Net loss
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—
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—
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|
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—
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(2,579,604
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)
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—
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|
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(2,579,604
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)
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Unrealized change in fair value of investments, net of tax
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—
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|
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—
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—
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—
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(661
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)
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(661
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)
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Issuance of common stock
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6,900
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|
69
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|
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729,468
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|
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—
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|
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—
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729,537
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Issuance of restricted stock awards
|
471
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|
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5
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(5
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)
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|
—
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|
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—
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|
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—
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Common stock reacquired and retired
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(194
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)
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(2
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)
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(21,238
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)
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|
—
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|
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—
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(21,240
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)
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Restricted stock forfeited and retired
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(90
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)
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(1
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)
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|
1
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|
|
—
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|
|
—
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|
|
—
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Exercise of stock options
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142
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|
|
1
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|
|
8,450
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|
|
—
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|
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—
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|
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8,451
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Stock-based compensation
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—
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|
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—
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|
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36,232
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|
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—
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|
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—
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36,232
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Stock-based compensation tax benefit
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—
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—
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|
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12,988
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—
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—
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12,988
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Balance, December 31, 2015
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94,821
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|
948
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|
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2,762,976
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(306,008
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)
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441
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|
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2,458,357
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Dividends paid on stock awards subsequently forfeited
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—
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—
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|
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2
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|
|
35
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|
|
—
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|
|
37
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|
Dividends
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—
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|
|
—
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|
|
—
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|
|
(7,583
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)
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|
—
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|
|
(7,583
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)
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Dividends in excess of retained earnings
|
—
|
|
|
—
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|
|
(22,805
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)
|
|
—
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|
|
—
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|
|
(22,805
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)
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Net loss
|
—
|
|
|
—
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|
|
—
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|
|
(408,803
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)
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|
—
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|
|
(408,803
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)
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Unrealized change in fair value of investments, net of tax
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—
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|
|
—
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|
|
—
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|
|
—
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|
|
504
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|
|
504
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|
Issuance of restricted stock awards
|
479
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|
|
5
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|
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(5
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)
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|
—
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|
|
—
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|
|
—
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Common stock reacquired and retired
|
(208
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)
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|
(3
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)
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(26,622
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)
|
|
—
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|
|
—
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|
|
(26,625
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)
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Restricted stock forfeited and retired
|
(32
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)
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|
—
|
|
|
—
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|
|
—
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|
|
—
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|
|
—
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Exercise of stock options
|
64
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|
|
1
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|
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4,803
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|
|
—
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|
|
—
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|
|
4,804
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|
Stock-based compensation
|
—
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|
|
—
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|
|
45,103
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|
|
—
|
|
|
—
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|
|
45,103
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Balance, December 31, 2016
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95,124
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|
|
951
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|
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2,763,452
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|
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(722,359
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)
|
|
945
|
|
|
2,042,989
|
|
Dividends paid on stock awards subsequently forfeited
|
—
|
|
|
—
|
|
|
11
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|
|
32
|
|
|
—
|
|
|
43
|
|
Dividends in excess of retained earnings
|
—
|
|
|
—
|
|
|
(30,489
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)
|
|
—
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|
|
—
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|
|
(30,489
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)
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Net income
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—
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|
|
—
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|
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—
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|
494,329
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|
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—
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|
|
494,329
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|
Unrealized change in fair value of investments, net of tax
|
—
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|
|
—
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|
|
—
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|
|
—
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|
|
1,254
|
|
|
1,254
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|
Issuance of restricted stock awards
|
552
|
|
|
5
|
|
|
(5
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)
|
|
—
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|
|
—
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|
|
—
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Common stock reacquired and retired
|
(204
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)
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|
(2
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)
|
|
(21,667
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)
|
|
—
|
|
|
—
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|
|
(21,669
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)
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Restricted stock forfeited and retired
|
(41
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)
|
|
—
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|
|
—
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|
|
—
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|
|
—
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|
|
—
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|
Exercise of stock options
|
6
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|
|
—
|
|
|
394
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|
|
—
|
|
|
—
|
|
|
394
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|
Stock-based compensation
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—
|
|
|
—
|
|
|
48,321
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|
|
—
|
|
|
—
|
|
|
48,321
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|
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6)
|
—
|
|
|
—
|
|
|
4,393
|
|
|
28,739
|
|
|
—
|
|
|
33,132
|
|
Other
|
—
|
|
|
—
|
|
|
(26
|
)
|
|
—
|
|
|
—
|
|
|
(26
|
)
|
Balance, December 31, 2017
|
95,437
|
|
|
$
|
954
|
|
|
$
|
2,764,384
|
|
|
$
|
(199,259
|
)
|
|
$
|
2,199
|
|
|
$
|
2,568,278
|
|
See accompanying notes to Consolidated Financial Statements.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, and New Mexico.
Basis of Presentation
Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation. Certain amounts in the prior year financial statements have been reclassified to conform to the 2017 financial statement presentation.
Segment Information
We have determined that our business is comprised of only
one
segment because our gathering, processing, and marketing activities are ancillary to our production operations.
Use of Estimates
The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies. We analyze our estimates and base them on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.
The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.
Cash and Cash Equivalents
Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of three months or less. Cash equivalents are stated at cost, which approximates market value.
Oil and Gas Well Equipment and Supplies
Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Declines in the price of oil and gas well equipment and supplies in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Oil and Gas Properties
We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the acquisition, exploration, and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Expenditures for maintenance and repairs are charged to production expense in the period incurred.
Under the full cost method of accounting, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at
10%
of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.
At
December 31, 2017
, the carrying value of our oil and gas properties subject to the test did not exceed the calculated value of the ceiling limitation and, therefore, we did not recognize an impairment. However, a decline of approximately
19%
or more in the value of the ceiling limitation would have resulted in an impairment. For the years ended
December 31, 2016
and
2015
, full year impairments totaled
$757.7 million
(
$481.4 million
, net of tax) and
$4.03 billion
(
$2.56 billion
, net of tax), respectively. These impairments resulted primarily from the impact of decreases in the trailing twelve-month average prices for oil, gas, and NGLs utilized in determining the future net revenues from proved reserves. The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. The calculated ceiling limitation is not intended to be indicative of the fair market
value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date.
Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities, commodity prices, and impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes.
The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors.
Fixed Assets
Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from
3
to
30 years
.
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. In performing the goodwill test, we compare the fair value of our reporting unit with its carrying amount. If the carrying amount of the reporting unit were to exceed its fair value, an impairment charge would be recognized in the amount of this excess, limited to the total amount of goodwill allocated to that reporting unit.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. We have historically tested goodwill for impairment as of December 31 each year; however, in 2017 we elected to change the date of our annual goodwill impairment test to October 31. We do not believe a change in the goodwill impairment testing date represents a material change to a method of applying an accounting principle because the change in impairment testing date does not have a material effect on our financial statements in light of the internal controls and requirements to assess goodwill impairment upon certain triggering events. Based upon our assessment as of October 31, 2017, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become unfavorable.
Revenue Recognition
Oil, Gas, and NGL Sales
Revenue is recognized from the sales of oil, gas, and NGLs when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured. There is a ready market for our products and sales occur soon after production.
Gas Gathering
When we transport and/or process third-party gas associated with our equity gas, we recognize revenue for the fees charged to third-parties for such services.
Gas Marketing
When we market and sell gas for working interest owners we act as agent under short-term sales and supply agreements and earn a fee for such services. Revenues from such services are recognized as gas is delivered.
Gas Imbalances
We use the sales method of accounting for gas imbalances. Revenue from the sale of gas is recorded on the basis of gas actually sold by us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.
General and Administrative Expenses
General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting.
Derivatives
Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 4 for additional information regarding our derivative instruments.
Income Taxes
We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. We classify all deferred tax assets and liabilities as non-current. We routinely assess the realizability of our deferred tax assets. We routinely assess the realizability of our deferred tax assets. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, which is affected by factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. If we conclude that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. We regularly assess and, if required, establish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 for additional information regarding
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
our income taxes, including the impact of H.R.1, commonly referred to as the Tax Cuts and Jobs Act, which the U.S. enacted on December 22, 2017.
Contingencies
A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and determine when we should record losses for these items based on information available to us. See Note 10 for additional information regarding our contingencies.
Asset Retirement Obligations
We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the abandonment of wells, the removal of facilities and equipment, and site restorations. In periods subsequent to the initial measurement of an asset retirement obligation at present value, a period-to-period increase in the carrying amount of the liability is recognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to the carrying amount of the liability. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are included as a component of the DD&A calculations. The current portion of our asset retirement obligations is recorded in “Accrued liabilities — Other” in the accompanying consolidated balance sheets and cash payments for settlements of retirement obligations are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note 8 for additional information regarding our asset retirement obligations.
Stock-based Compensation
We recognize compensation cost related to all stock-based awards in the financial statements based on their estimated grant date fair value. We grant various types of stock-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions), and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration, and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 6 for additional information regarding our stock-based compensation.
Earnings (Loss) per Share
We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested share-based payment awards, consisting of restricted stock and units, qualify as participating securities. See Note 7 for additional information regarding our earnings per share.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09,
Revenue from Contracts with Customers (Topic 606)
, which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in this update supersedes the revenue recognition requirements in Topic 605,
Revenue Recognition
, and most industry-specific guidance throughout the Industry Topics of the Codification. Entities can choose to adopt the standard using either the full retrospective approach or a modified retrospective approach. We will adopt the standard effective January 1, 2018, utilizing the modified retrospective approach, which will be applied to contracts that were not completed as of January 1, 2018. The new standard will not have an impact on net income (loss) or cash flows from operations; however, certain costs previously classified as Transportation, processing, and other operating expenses in the statement of operations will be reflected as deductions from revenue under the new standard. Had Topic 606 been in effect for the fourth quarter of 2017, Revenue and Transportation, processing and other operating expenses for the quarter would have each been reduced by an estimated range of
$15.0 million
to
$16.0 million
.
In February 2016, the FASB issued ASU 2016-02,
Leases (Topic 842)
. The key provision of this ASU is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months. Under current GAAP, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases. Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of assets and liabilities on the balance sheet. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are in the process of evaluating the potential impact of adopting this guidance, but believe the primary effect will be to record assets and liabilities for contracts currently accounted for as operating leases. We do not intend to adopt the standard early.
In January 2018, the FASB issued ASU 2018-01,
Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842
. This ASU provides an optional transition practical expedient to not evaluate under Topic 842 (discussed above) existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. Under the full cost method of accounting, we capitalize to oil and gas properties all property acquisition, exploration, and development costs, which include the costs of land easements. We plan to elect this practical expedient and continue to apply our current accounting policy to account for land easements that existed before our adoption of Topic 842 and will evaluate new or modified land easements under Topic 842 upon our adoption of Topic 842. We are in the process of evaluating the potential impact of adopting this guidance, and do not intend to adopt the standard early.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. CAPITAL STOCK
Authorized capital stock consists of
200 million
shares of common stock and
15 million
shares of preferred stock. At
December 31, 2017
, there were
95.4 million
shares of common stock and
no
shares of preferred stock outstanding. See our Consolidated Statements of Stockholders’ Equity for detailed capital stock activity.
In May 2015, we completed an underwritten public offering of
6.9 million
shares of common stock, which included
0.9 million
shares of common stock issued pursuant to an overallotment option to purchase additional shares granted to the underwriters. The stock was sold to the public at
$109.00
per share, with a par value of
$0.01
, and we received net proceeds of
$729.5 million
from the sale, after deducting underwriting fees.
Dividends
A cash dividend has been paid to stockholders in every quarter since the first quarter of 2006. A quarterly dividend of
$0.08
per share was declared in each quarter of 2017 and 2016 and a quarterly dividend of
$0.16
per share was declared in each quarter of 2015. We typically declare dividends in one quarter and pay them in the next quarter. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.
3. LONG-TERM DEBT
Long-term debt at
December 31, 2017
and
2016
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
(in thousands)
|
|
Principal
|
|
Unamortized Debt
Issuance Costs and Discount (1)
|
|
Long-term
Debt, net
|
|
Principal
|
|
Unamortized Debt
Issuance Costs
|
|
Long-term
Debt, net
|
5.875% Senior Notes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
750,000
|
|
|
$
|
(5,691
|
)
|
|
$
|
744,309
|
|
4.375% Senior Notes
|
|
750,000
|
|
|
(5,383
|
)
|
|
744,617
|
|
|
750,000
|
|
|
(6,370
|
)
|
|
743,630
|
|
3.90% Senior Notes
|
|
750,000
|
|
|
(7,697
|
)
|
|
742,303
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total long-term debt
|
|
$
|
1,500,000
|
|
|
$
|
(13,080
|
)
|
|
$
|
1,486,920
|
|
|
$
|
1,500,000
|
|
|
$
|
(12,061
|
)
|
|
$
|
1,487,939
|
|
________________________________________
|
|
(1)
|
At
December 31, 2017
, the unamortized debt issuance costs and discount related to the
3.90%
notes were
$5.9 million
and
$1.8 million
, respectively. The
4.375%
notes were issued at par.
|
Bank Debt
In October 2015, we entered into a new senior unsecured revolving credit facility (“Credit Facility”) which matures October 16, 2020. The Credit Facility has aggregate commitments of
$1.0 billion
, with an option to increase aggregate commitments to
$1.25 billion
at any time. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of
December 31, 2017
, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of
$2.5 million
outstanding, leaving an unused borrowing availability of
$997.5 million
.
At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus
1.125
-
2.0%
based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus
0.125
-
1.0%
, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of
0.125
-
0.35%
, based on the credit rating for our senior unsecured long-term debt.
The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than
65%
. As of
December 31, 2017
, we were in compliance with all of the financial covenants.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At
December 31, 2017
and
2016
, we had
$3.4 million
and
$4.5 million
, respectively, of unamortized debt issuance costs associated with our Credit Facility which were recorded as deferred assets and included in Other assets, net in our balance sheets. The costs are being amortized to interest expense ratably over the life of the Credit Facility.
Senior Notes
On April 10, 2017, we completed a cash tender offer to purchase any of our
5.875%
notes for cash consideration of
$1,031.67
per
$1,000
principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with
$253.5 million
aggregate principal amount of the notes validly tendered. We settled these tendered notes for
$268.1 million
, including accrued interest. On May 12, 2017, we completed a redemption of the
5.875%
notes remaining outstanding for
$1,029.38
per
$1,000
principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for
$512.0 million
, including accrued interest. We recognized a loss on early extinguishment of debt related to these transactions of
$28.2 million
, composed primarily of tender and redemption premiums of
$22.6 million
and the write-off of
$5.3 million
of unamortized debt issuance costs. The original maturity date of the
5.875%
notes was
May 1, 2022
.
On April 10, 2017, we issued
$750 million
aggregate principal amount of
3.90%
senior unsecured notes due May 15, 2027 at
99.748%
of par to yield
3.93%
per annum. We received
$741.8 million
in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs. The notes bear an annual interest rate of
3.90%
and interest is payable semiannually on May 15 and November 15, with the first payment occurring November 15, 2017. Along with cash on hand, we used the proceeds to fund the settlement of the tendered and redeemed
5.875%
notes.
In June 2014, we issued
$750 million
aggregate principal amount of
4.375%
senior unsecured notes at par. These notes are due
June 1, 2024
and interest is payable semiannually on June 1 and December 1.
Each of our senior unsecured notes is governed by an indenture containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of
December 31, 2017
. The effective interest rate on the
4.375%
notes and the
3.90%
notes, including the amortization of debt issuance costs and discount, as applicable, is
4.50%
and
4.01%
, respectively.
4. DERIVATIVE INSTRUMENTS
We periodically use derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels.
As of
December 31, 2017
, we have entered into oil and gas collars and oil basis swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price minus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Midland price. For our Permian and Mid-Continent gas production, the contract prices in our collars are consistent with the index prices used to sell our production. The following tables summarize our outstanding derivative contracts as of
December 31, 2017
:
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Collars:
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls)
|
|
2,610,000
|
|
|
2,093,000
|
|
|
1,748,000
|
|
|
1,196,000
|
|
|
7,647,000
|
|
Weighted Avg Price - Floor
|
|
$
|
47.28
|
|
|
$
|
47.26
|
|
|
$
|
46.68
|
|
|
$
|
48.00
|
|
|
$
|
47.25
|
|
Weighted Avg Price - Ceiling
|
|
$
|
56.33
|
|
|
$
|
55.61
|
|
|
$
|
54.90
|
|
|
$
|
55.10
|
|
|
$
|
55.62
|
|
|
|
|
|
|
|
|
|
|
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls)
|
|
630,000
|
|
|
637,000
|
|
|
—
|
|
|
—
|
|
|
1,267,000
|
|
Weighted Avg Price - Floor
|
|
$
|
48.00
|
|
|
$
|
48.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
48.00
|
|
Weighted Avg Price - Ceiling
|
|
$
|
56.09
|
|
|
$
|
56.09
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
56.09
|
|
________________________________________
|
|
(1)
|
The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Collars:
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PEPL
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
11,700,000
|
|
|
9,100,000
|
|
|
6,440,000
|
|
|
3,680,000
|
|
|
30,920,000
|
|
Weighted Avg Price - Floor
|
|
$
|
2.57
|
|
|
$
|
2.47
|
|
|
$
|
2.43
|
|
|
$
|
2.43
|
|
|
$
|
2.49
|
|
Weighted Avg Price - Ceiling
|
|
$
|
2.93
|
|
|
$
|
2.81
|
|
|
$
|
2.67
|
|
|
$
|
2.66
|
|
|
$
|
2.81
|
|
Perm EP
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
8,100,000
|
|
|
6,370,000
|
|
|
4,600,000
|
|
|
2,760,000
|
|
|
21,830,000
|
|
Weighted Avg Price - Floor
|
|
$
|
2.52
|
|
|
$
|
2.39
|
|
|
$
|
2.34
|
|
|
$
|
2.33
|
|
|
$
|
2.42
|
|
Weighted Avg Price - Ceiling
|
|
$
|
2.84
|
|
|
$
|
2.67
|
|
|
$
|
2.53
|
|
|
$
|
2.52
|
|
|
$
|
2.68
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PEPL
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
2,700,000
|
|
|
2,730,000
|
|
|
—
|
|
|
—
|
|
|
5,430,000
|
|
Weighted Avg Price - Floor
|
|
$
|
2.40
|
|
|
$
|
2.40
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.40
|
|
Weighted Avg Price - Ceiling
|
|
$
|
2.67
|
|
|
$
|
2.67
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.67
|
|
Perm EP
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
1,800,000
|
|
|
1,820,000
|
|
|
—
|
|
|
—
|
|
|
3,620,000
|
|
Weighted Avg Price - Floor
|
|
$
|
2.30
|
|
|
$
|
2.30
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.30
|
|
Weighted Avg Price - Ceiling
|
|
$
|
2.49
|
|
|
$
|
2.49
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.49
|
|
________________________________________
|
|
(1)
|
The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.
|
|
|
(2)
|
The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.
|
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Basis Swaps:
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
WTI Midland
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls)
|
|
1,170,000
|
|
|
1,183,000
|
|
|
1,196,000
|
|
|
736,000
|
|
|
4,285,000
|
|
Weighted Avg Differential (2)
|
|
$
|
(0.72
|
)
|
|
$
|
(0.72
|
)
|
|
$
|
(0.72
|
)
|
|
$
|
(0.58
|
)
|
|
$
|
(0.69
|
)
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
WTI Midland
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls)
|
|
450,000
|
|
|
455,000
|
|
|
—
|
|
|
—
|
|
|
905,000
|
|
Weighted Avg Differential (2)
|
|
$
|
(0.47
|
)
|
|
$
|
(0.47
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.47
|
)
|
________________________________________
|
|
(1)
|
The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.
|
|
|
(2)
|
The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table.
|
The following tables summarize our derivative contracts entered into subsequent to
December 31, 2017
through February 22, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Collars:
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
WTI (1)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls)
|
|
—
|
|
|
546,000
|
|
|
552,000
|
|
|
552,000
|
|
|
1,650,000
|
|
Weighted Avg Price - Floor
|
|
$
|
—
|
|
|
$
|
50.00
|
|
|
$
|
50.00
|
|
|
$
|
50.00
|
|
|
$
|
50.00
|
|
Weighted Avg Price - Ceiling
|
|
$
|
—
|
|
|
$
|
66.82
|
|
|
$
|
66.82
|
|
|
$
|
66.82
|
|
|
$
|
66.82
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
WTI (1)
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls)
|
|
540,000
|
|
|
546,000
|
|
|
552,000
|
|
|
—
|
|
|
1,638,000
|
|
Weighted Avg Price - Floor
|
|
$
|
50.00
|
|
|
$
|
50.00
|
|
|
$
|
50.00
|
|
|
$
|
—
|
|
|
$
|
50.00
|
|
Weighted Avg Price - Ceiling
|
|
$
|
66.82
|
|
|
$
|
66.82
|
|
|
$
|
66.82
|
|
|
$
|
—
|
|
|
$
|
66.82
|
|
________________________________________
|
|
(1)
|
The index price for these collars is WTI as quoted on the NYMEX.
|
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Collars:
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
|
2018:
|
|
|
|
|
|
|
|
|
|
|
PEPL
(1)
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
—
|
|
|
1,820,000
|
|
|
1,840,000
|
|
|
1,840,000
|
|
|
5,500,000
|
|
Weighted Avg Price - Floor
|
|
$
|
—
|
|
|
$
|
1.98
|
|
|
$
|
1.98
|
|
|
$
|
1.98
|
|
|
$
|
1.98
|
|
Weighted Avg Price - Ceiling
|
|
$
|
—
|
|
|
$
|
2.16
|
|
|
$
|
2.16
|
|
|
$
|
2.16
|
|
|
$
|
2.16
|
|
Perm EP
(2)
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
—
|
|
|
1,820,000
|
|
|
1,840,000
|
|
|
1,840,000
|
|
|
5,500,000
|
|
Weighted Avg Price - Floor
|
|
$
|
—
|
|
|
$
|
1.65
|
|
|
$
|
1.65
|
|
|
$
|
1.65
|
|
|
$
|
1.65
|
|
Weighted Avg Price - Ceiling
|
|
$
|
—
|
|
|
$
|
1.80
|
|
|
$
|
1.80
|
|
|
$
|
1.80
|
|
|
$
|
1.80
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
PEPL
(1)
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
1,800,000
|
|
|
1,820,000
|
|
|
1,840,000
|
|
|
—
|
|
|
5,460,000
|
|
Weighted Avg Price - Floor
|
|
$
|
1.98
|
|
|
$
|
1.98
|
|
|
$
|
1.98
|
|
|
$
|
—
|
|
|
$
|
1.98
|
|
Weighted Avg Price - Ceiling
|
|
$
|
2.16
|
|
|
$
|
2.16
|
|
|
$
|
2.16
|
|
|
$
|
—
|
|
|
$
|
2.16
|
|
Perm EP
(2)
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
1,800,000
|
|
|
1,820,000
|
|
|
1,840,000
|
|
|
—
|
|
|
5,460,000
|
|
Weighted Avg Price - Floor
|
|
$
|
1.65
|
|
|
$
|
1.65
|
|
|
$
|
1.65
|
|
|
$
|
—
|
|
|
$
|
1.65
|
|
Weighted Avg Price - Ceiling
|
|
$
|
1.80
|
|
|
$
|
1.80
|
|
|
$
|
1.80
|
|
|
$
|
—
|
|
|
$
|
1.80
|
|
________________________________________
|
|
(1)
|
The index price for these collars is PEPL as quoted in Platt’s Inside FERC.
|
|
|
(2)
|
The index price for these collars is Perm EP as quoted in Platt’s Inside FERC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Basis Swaps:
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
WTI Midland
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls)
|
|
—
|
|
|
91,000
|
|
|
92,000
|
|
|
92,000
|
|
|
275,000
|
|
Weighted Avg Differential (2)
|
|
$
|
—
|
|
|
$
|
(0.70
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.70
|
)
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
WTI Midland
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls)
|
|
90,000
|
|
|
91,000
|
|
|
92,000
|
|
|
—
|
|
|
273,000
|
|
Weighted Avg Differential (2)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
—
|
|
|
$
|
(0.70
|
)
|
________________________________________
|
|
(1)
|
The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.
|
|
|
(2)
|
The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table.
|
Derivative Gains and Losses
Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the components of (Gain) loss on derivative instruments, net for the periods indicated.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Change in fair value of derivative instruments, net:
|
|
|
|
|
|
|
|
|
|
Gas contracts
|
|
$
|
(40,226
|
)
|
|
$
|
27,462
|
|
|
$
|
(4,472
|
)
|
Oil contracts
|
|
17,383
|
|
|
35,724
|
|
|
(6,774
|
)
|
|
|
(22,843
|
)
|
|
63,186
|
|
|
(11,246
|
)
|
Cash (receipts) payments on derivative instruments, net:
|
|
|
|
|
|
|
|
|
|
Gas contracts
|
|
(4,557
|
)
|
|
(6,467
|
)
|
|
—
|
|
Oil contracts
|
|
6,190
|
|
|
(970
|
)
|
|
—
|
|
|
|
1,633
|
|
|
(7,437
|
)
|
|
—
|
|
(Gain) loss on derivative instruments, net
|
|
$
|
(21,210
|
)
|
|
$
|
55,749
|
|
|
$
|
(11,246
|
)
|
Derivative Fair Value
Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to enforceable master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our accounting policy is to not offset asset and liability positions in our balance sheets.
The following tables present the amounts and classifications of our derivative assets and liabilities as of
December 31, 2017
and
2016
, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
(in thousands)
|
|
Balance Sheet Location
|
|
Asset
|
|
Liability
|
Gas contracts
|
|
Current assets — Derivative instruments
|
|
$
|
15,151
|
|
|
$
|
—
|
|
Gas contracts
|
|
Non-current assets — Derivative instruments
|
|
2,086
|
|
|
—
|
|
Oil contracts
|
|
Current liabilities — Derivative instruments
|
|
—
|
|
|
42,066
|
|
Oil contracts
|
|
Non-current liabilities — Derivative instruments
|
|
—
|
|
|
4,268
|
|
Total gross amounts presented in the balance sheet
|
|
17,237
|
|
|
46,334
|
|
Less: gross amounts not offset in the balance sheet
|
|
(17,237
|
)
|
|
(17,237
|
)
|
Net amount
|
|
$
|
—
|
|
|
$
|
29,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
(in thousands)
|
|
Balance Sheet Location
|
|
Asset
|
|
Liability
|
Oil contracts
|
|
Current liabilities — Derivative instruments
|
|
$
|
—
|
|
|
$
|
27,892
|
|
Gas contracts
|
|
Current liabilities — Derivative instruments
|
|
—
|
|
|
21,478
|
|
Oil contracts
|
|
Non-current liabilities — Derivative instruments
|
|
—
|
|
|
1,059
|
|
Gas contracts
|
|
Non-current liabilities — Derivative instruments
|
|
—
|
|
|
1,511
|
|
Total gross amounts presented in the balance sheet
|
|
—
|
|
|
51,940
|
|
Less: gross amounts not offset in the balance sheet
|
|
—
|
|
|
—
|
|
Net amount
|
|
$
|
—
|
|
|
$
|
51,940
|
|
We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which have a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our derivative liability positions. Because some of the member banks have discontinued derivative activities, in the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.
The following table provides fair value measurement information for certain assets and liabilities as of
December 31, 2017
and
2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
(in thousands)
|
|
Book Value
|
|
Fair Value
|
|
Book Value
|
|
Fair Value
|
Financial Assets (Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
5.875% Notes due 2022
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(750,000
|
)
|
|
$
|
(782,835
|
)
|
4.375% Notes due 2024
|
|
$
|
(750,000
|
)
|
|
$
|
(797,010
|
)
|
|
$
|
(750,000
|
)
|
|
$
|
(779,453
|
)
|
3.90% Notes due 2027
|
|
$
|
(750,000
|
)
|
|
$
|
(767,813
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Derivative instruments — assets
|
|
$
|
17,237
|
|
|
$
|
17,237
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Derivative instruments — liabilities
|
|
$
|
(46,334
|
)
|
|
$
|
(46,334
|
)
|
|
$
|
(51,940
|
)
|
|
$
|
(51,940
|
)
|
Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The fair value (Level 1) of our fixed rate notes was based on their last traded value before period end. The fair value of our derivative instruments (Level 2) was estimated using option pricing models. These models use certain variables including forward price and volatility curves and the strike prices for the instruments. The fair value estimates are adjusted relative to non-performance risk as appropriate. See Note 4 for further information on the fair value of our derivative instruments.
Other Financial Instruments
The carrying amounts of our cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in “Accrued liabilities — other” at
December 31, 2017
are: (i) accrued operating expenses of approximately
$61.3 million
and (ii) accrued general and administrative, primarily payroll-related, costs of approximately
$54.6 million
. Included in “Accrued liabilities — other” at
December 31, 2016
are: (i) accrued operating expenses of approximately
$53.9 million
and (ii) accrued general and administrative, primarily payroll-related, costs of approximately
$43.5 million
.
Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.
We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary.
We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At
December 31, 2017
and
2016
, the allowance for doubtful accounts totaled
$2.2 million
and
$1.6 million
, respectively.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Major Customers
In
2017
, our major customers were Energy Transfer Partners, L.P. (“Energy Transfer Partners”) and Plains All American Pipeline, L.P. (“Plains All American”), which accounted for
21%
and
13%
, respectively, of our consolidated revenues that year. In 2017, the revenue totals for Energy Transfer Partners include revenue from Sunoco Logistics Partners L.P. (“Sunoco”) since the two entities merged in 2017. Sunoco was our major customer in
2016
, accounting for
20%
of our consolidated revenues that year. In
2015
, our major customers were Sunoco and Enterprise Products Partners L.P., which accounted for
21%
and
17%
, respectively, of our consolidated revenues that year.
If any one of our major customers was to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production with some delay. If multiple significant customers were to discontinue purchasing our production, we believe there would be challenges initially, but ample markets to handle the disruption.
6. STOCK-BASED AND OTHER COMPENSATION
Equity Incentive Plan
Our 2014 Equity Incentive Plan (the “2014 Plan”) was approved by stockholders in May 2014 and our previous plan was terminated at that time. Outstanding awards under the previous plan were not impacted. A total of
6.6 million
shares of common stock may be issued under the 2014 Plan, including shares available from the previous plan. The 2014 Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, dividend equivalents, and other stock-based awards.
Stock-based Compensation Cost
We have recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Restricted stock awards:
|
|
|
|
|
|
|
|
|
|
Performance stock awards
|
|
$
|
26,020
|
|
|
$
|
24,183
|
|
|
$
|
18,991
|
|
Service-based stock awards
|
|
19,746
|
|
|
18,391
|
|
|
14,547
|
|
|
|
45,766
|
|
|
42,574
|
|
|
33,538
|
|
Stock option awards
|
|
2,599
|
|
|
2,565
|
|
|
2,803
|
|
Total stock compensation cost
|
|
48,365
|
|
|
45,139
|
|
|
36,341
|
|
Less amounts capitalized to oil and gas properties
|
|
(22,109
|
)
|
|
(20,616
|
)
|
|
(16,782
|
)
|
Stock compensation expense
|
|
$
|
26,256
|
|
|
$
|
24,523
|
|
|
$
|
19,559
|
|
Periodic stock compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. The increase in total stock compensation cost in
2017
as compared to
2016
is primarily
due to awards granted either during or subsequent to
2016
. These increases were partially offset by awards vesting prior to or during
2017
.
We adopted Accounting Standards Update 2016-09,
Improvements to Employee Share-Based Payment Accounting
(“ASU 2016-09”) on January 1, 2017. ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows. Pursuant to ASU 2016-09, we made an accounting policy election to account for forfeitures in compensation cost when they occur, rather than including an estimate of the number of awards that are expected to vest in our compensation cost. The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by
$33.1 million
, reduced beginning accumulated deficit by
$28.7 million
, and increased beginning additional paid-in capital by
$4.4 million
. The
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to the payment of employee tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method. In accordance with this method, we adjusted the statement of cash flows for the year ended
December 31, 2016
by increasing both net cash provided by operating activities and net cash used by financing activities by
$26.6 million
for the payment of employee tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the year ended
December 31, 2016
. For the year ended
December 31, 2015
, we adjusted the statement of cash flows for the payment of employee tax withholdings on the net settlement of equity-classified awards as well as for the classification of excess tax benefits by increasing net cash provided by operating activities and decreasing net cash provided by financing activities by
$34.2 million
.
Restricted Stock
The following table provides information about restricted stock awards granted during the last three years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
Number
of Shares
|
|
Weighted
Average
Grant Date
Fair Value
|
|
Number
of Shares
|
|
Weighted
Average
Grant Date
Fair Value
|
|
Number
of Shares
|
|
Weighted
Average
Grant Date
Fair Value
|
Performance stock awards
|
300,525
|
|
|
$
|
89.46
|
|
|
269,915
|
|
|
$
|
117.63
|
|
|
263,939
|
|
|
$
|
87.12
|
|
Service-based stock awards
|
251,312
|
|
|
$
|
94.04
|
|
|
208,724
|
|
|
$
|
114.61
|
|
|
207,180
|
|
|
$
|
114.80
|
|
Total restricted stock awards
|
551,837
|
|
|
$
|
91.55
|
|
|
478,639
|
|
|
$
|
116.31
|
|
|
471,119
|
|
|
$
|
99.29
|
|
Performance stock awards were granted to eligible executives and are subject to service and market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance. After
three years
of continued service, an executive will be entitled to vest in
50%
to
100%
of the award. In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. Service-based stock awards granted to other eligible employees and non-employee directors have vesting schedules ranging from
one
to
five years
. The majority of our service-based stock awards cliff vest
five years
from the grant date.
Compensation cost for the performance stock awards is based on the grant date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for the service-based stock awards is based upon the grant date market value of the award. Such costs are recognized ratably over the applicable vesting period.
The following table provides information on restricted stock activity during the year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service-based
|
|
Performance
(subject to market conditions)
|
|
Number of
Shares
|
|
Weighted
Average
Grant Date
Fair Value
|
|
Number of
Shares
|
|
Weighted
Average
Grant Date
Fair Value
|
Outstanding as of January 1, 2017
|
934,723
|
|
|
$
|
96.57
|
|
|
809,270
|
|
|
$
|
96.41
|
|
Vested
|
(234,468
|
)
|
|
$
|
63.49
|
|
|
(275,416
|
)
|
|
$
|
84.50
|
|
Granted
|
251,312
|
|
|
$
|
94.04
|
|
|
300,525
|
|
|
$
|
89.46
|
|
Forfeited
|
(41,316
|
)
|
|
$
|
105.83
|
|
|
—
|
|
|
$
|
—
|
|
Outstanding as of December 31, 2017
|
910,251
|
|
|
$
|
103.98
|
|
|
834,379
|
|
|
$
|
97.83
|
|
The total fair value of restricted stock that vested was
$54.4 million
in
2017
,
$67.9 million
in
2016
, and
$52.2 million
in
2015
.
Unrecognized compensation cost related to unvested restricted stock at
December 31, 2017
was
$105.6 million
. We expect to recognize that cost over a weighted average period of
2.8 years
.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Restricted Units
As of
December 31, 2017
and
2016
, we had
8,838
restricted units outstanding. These represent restricted units held by a non-employee director who has elected to defer payment of common stock represented by the units until termination of his service on the Board of Directors.
Stock Options
Options outstanding as of
December 31, 2017
expire
seven
to
ten years
from the grant date and have service-based vesting whereby the awards vest in increments of one-third on each of the first
three
anniversary dates of the grant. The exercise price for an option under the 2014 Plan is the closing price of our common stock as reported by the New York Stock Exchange (“NYSE”) on the date of grant. The previous plans provided that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the NYSE on the date of grant.
Compensation cost related to stock options is based on the grant date fair value of the award and is recognized ratably over the applicable vesting period. We estimate the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the expected years until exercise. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.
The following summarizes information regarding options granted, including the assumptions used to determine the fair value of those options.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Options granted
|
96,100
|
|
|
89,850
|
|
|
69,000
|
|
Weighted average grant date fair value
|
$
|
28.37
|
|
|
$
|
33.38
|
|
|
$
|
37.56
|
|
Weighted average exercise price
|
$
|
92.37
|
|
|
$
|
114.07
|
|
|
$
|
115.28
|
|
Total fair value (in thousands)
|
$
|
2,727
|
|
|
$
|
2,999
|
|
|
$
|
2,592
|
|
Expected years until exercise
|
4.5
|
|
|
4.0
|
|
|
5.0
|
|
Expected stock volatility
|
35.0
|
%
|
|
36.7
|
%
|
|
36.6
|
%
|
Dividend yield
|
0.3
|
%
|
|
0.3
|
%
|
|
0.6
|
%
|
Risk-free interest rate
|
1.7
|
%
|
|
1.0
|
%
|
|
1.6
|
%
|
Information about outstanding stock options is summarized below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Options
|
|
Weighted
Average
Exercise
Price
|
|
Weighted
Average
Remaining
Term
|
|
Aggregate
Intrinsic
Value
(in thousands)
|
Outstanding as of January 1, 2017
|
307,810
|
|
|
$
|
101.72
|
|
|
|
|
|
|
Exercised
|
(5,768
|
)
|
|
$
|
68.33
|
|
|
|
|
|
|
Granted
|
96,100
|
|
|
$
|
92.37
|
|
|
|
|
|
|
Canceled
|
(1,665
|
)
|
|
$
|
139.02
|
|
|
|
|
|
|
Forfeited
|
(13,789
|
)
|
|
$
|
88.92
|
|
|
|
|
|
|
Outstanding as of December 31, 2017
|
382,688
|
|
|
$
|
100.17
|
|
|
4.4 years
|
|
$
|
9,553
|
|
Exercisable as of December 31, 2017
|
209,782
|
|
|
$
|
98.55
|
|
|
3.2 years
|
|
$
|
6,020
|
|
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides information regarding options exercised and the grant date fair value of options vested.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Cash received from option exercises
|
|
$
|
394
|
|
|
$
|
4,804
|
|
|
$
|
8,451
|
|
Tax benefit from option exercises included in paid-in-capital
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,442
|
|
Intrinsic value of options exercised
|
|
$
|
257
|
|
|
$
|
2,994
|
|
|
$
|
7,467
|
|
Grant date fair value of options vested
|
|
$
|
2,227
|
|
|
$
|
2,486
|
|
|
$
|
2,734
|
|
The following summary reflects the status of non-vested stock options as of
December 31, 2017
and changes during the year.
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Options
|
|
Weighted
Average
Grant Date
Fair Value
|
|
Weighted
Average
Exercise
Price
|
Non-vested as of January 1, 2017
|
148,361
|
|
|
$
|
35.58
|
|
|
$
|
117.55
|
|
Vested
|
(57,766
|
)
|
|
$
|
38.55
|
|
|
$
|
128.59
|
|
Granted
|
96,100
|
|
|
$
|
28.37
|
|
|
$
|
92.37
|
|
Forfeited
|
(13,789
|
)
|
|
$
|
29.41
|
|
|
$
|
88.92
|
|
Non-vested as of December 31, 2017
|
172,906
|
|
|
$
|
31.08
|
|
|
$
|
102.15
|
|
As of
December 31, 2017
, there was
$4.1 million
of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost over a weighted average period of
1.9 years
.
Other Compensation
We maintain and sponsor a contributory 401(k) plan for our employees. Employer contributions related to the plan were
$10.4 million
,
$6.7 million
, and
$6.4 million
for
2017
,
2016
, and
2015
, respectively. Included in the 2017 amount are accrued employer discretionary contributions. No such employer discretionary contributions occurred in 2016 and 2015.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. EARNINGS (LOSS) PER SHARE
The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands, except per share data)
|
|
2017
|
|
2016
|
|
2015
|
Basic:
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
494,329
|
|
|
$
|
(408,803
|
)
|
|
$
|
(2,579,604
|
)
|
Participating securities’ share in earnings (1)
|
|
(8,551
|
)
|
|
—
|
|
|
—
|
|
Net income (loss) available to common stockholders
|
|
$
|
485,778
|
|
|
$
|
(408,803
|
)
|
|
$
|
(2,579,604
|
)
|
Diluted:
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
494,329
|
|
|
$
|
(408,803
|
)
|
|
$
|
(2,579,604
|
)
|
Participating securities’ share in earnings (1)
|
|
(8,548
|
)
|
|
—
|
|
|
—
|
|
Net income (loss) available to common stockholders
|
|
$
|
485,781
|
|
|
$
|
(408,803
|
)
|
|
$
|
(2,579,604
|
)
|
Shares:
|
|
|
|
|
|
|
|
|
|
Basic shares outstanding
|
|
93,466
|
|
|
93,379
|
|
|
92,992
|
|
Dilutive effect of stock options (2)
|
|
43
|
|
|
—
|
|
|
—
|
|
Fully diluted common stock
|
|
93,509
|
|
|
93,379
|
|
|
92,992
|
|
Earnings (loss) per share to common stockholders (3):
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
5.19
|
|
|
$
|
(4.38
|
)
|
|
$
|
(27.75
|
)
|
Diluted
|
|
$
|
5.19
|
|
|
$
|
(4.38
|
)
|
|
$
|
(27.75
|
)
|
________________________________________
|
|
(1)
|
Participating securities are not included in undistributed earnings when a loss exists.
|
|
|
(2)
|
Inclusion of certain shares would have an anti-dilutive effect; therefore,
302.9 thousand
,
2.1 million
, and
2.1 million
shares were excluded from the calculations for the years ended
December 31, 2017
,
2016
, and
2015
, respectively.
|
|
|
(3)
|
Earnings (loss) per share are based on actual figures rather than the rounded figures presented.
|
8. ASSET RETIREMENT OBLIGATIONS
The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended
December 31, 2017
and
2016
.
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2017
|
|
2016
|
Asset retirement obligation at January 1,
|
|
$
|
154,523
|
|
|
$
|
164,105
|
|
Liabilities incurred
|
|
17,996
|
|
|
3,914
|
|
Liability settlements and disposals
|
|
(12,947
|
)
|
|
(24,108
|
)
|
Accretion expense
|
|
7,534
|
|
|
7,595
|
|
Revisions of estimated liabilities
|
|
2,363
|
|
|
3,017
|
|
Asset retirement obligation at December 31,
|
|
169,469
|
|
|
154,523
|
|
Less current obligation
|
|
11,048
|
|
|
13,753
|
|
Long-term asset retirement obligation
|
|
$
|
158,421
|
|
|
$
|
140,770
|
|
Liabilities incurred in 2017 includes
$10.5 million
for the estimated liability to decommission two offshore properties in the Gulf of Mexico in which we were a prior lessee. In January 2018, the Bureau of Safety and Environmental Enforcement (“BSEE”) notified us and other prior lessees that the current lessee of the properties had filed a petition for relief under the bankruptcy code and, as a result, had defaulted on its obligation to decommission the properties. Consequently, BSEE ordered us and other prior lessees to decommission all wells, pipelines, platforms, and other facilities related to these properties. Our estimate of our liability may change as we refine our understanding of the extent of our obligations under the orders from BSEE and obtain additional information on decommissioning costs.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During
2017
and
2016
, the liability settlements and disposals included
$0.5 million
and
$14.9 million
, respectively, related to properties that were sold.
9. INCOME TAXES
The components of the provision for income taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Current taxes:
|
|
|
|
|
|
|
|
|
|
Federal (benefit) expense
|
|
$
|
(2,810
|
)
|
|
$
|
—
|
|
|
$
|
14,417
|
|
State (benefit) expense
|
|
(2
|
)
|
|
(1,115
|
)
|
|
293
|
|
|
|
(2,812
|
)
|
|
(1,115
|
)
|
|
14,710
|
|
Deferred taxes:
|
|
|
|
|
|
|
|
|
|
Federal expense (benefit)
|
|
173,859
|
|
|
(201,529
|
)
|
|
(1,386,086
|
)
|
State expense (benefit)
|
|
16,620
|
|
|
(11,757
|
)
|
|
(100,353
|
)
|
|
|
190,479
|
|
|
(213,286
|
)
|
|
(1,486,439
|
)
|
|
|
$
|
187,667
|
|
|
$
|
(214,401
|
)
|
|
$
|
(1,471,729
|
)
|
Federal income tax expense (benefit) for the years presented differs from the amounts that would be provided by applying the U.S. federal income tax rate, primarily due to the effect of state income taxes, non-deductible expenses, revisions, and changes in tax laws and tax rates enacted in the period. Reconciliations of the income tax expense (benefit) calculated at the federal statutory rate of
35%
to the total income tax expense (benefit) are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Provision at statutory rate
|
|
$
|
238,699
|
|
|
$
|
(218,122
|
)
|
|
$
|
(1,417,967
|
)
|
Effect of state taxes
|
|
10,074
|
|
|
(10,237
|
)
|
|
(64,794
|
)
|
Revision of previous balances
|
|
—
|
|
|
7,181
|
|
|
5,997
|
|
Tax credits and other permanent differences
|
|
5,442
|
|
|
5,296
|
|
|
5,035
|
|
Change in valuation allowance, net
|
|
486
|
|
|
1,481
|
|
|
—
|
|
Stock-based compensation
|
|
(5,888
|
)
|
|
—
|
|
|
—
|
|
Impact of reduction in federal statutory rate
|
|
(61,146
|
)
|
|
—
|
|
|
—
|
|
Income tax expense (benefit)
|
|
$
|
187,667
|
|
|
$
|
(214,401
|
)
|
|
$
|
(1,471,729
|
)
|
The company recorded a
$33.1 million
increase to the net operating loss deferred tax asset and corresponding increase to retained earnings in the first quarter of
2017
upon adoption of ASU 2016-09 for deductions taken for employee stock awards on the company’s tax returns in excess of amounts expensed through the company’s statement of operations. Pursuant to ASU 2016-09, excess tax benefits for employee share-based payments of
$5.9 million
were recognized in income tax expense in
2017
.
As a result of the enactment of H.R.1 on
December 22, 2017
, the company remeasured the deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the U.S. income tax rate from
35%
to
21%
for years after
2017
. As a result of this remeasurement, we recorded an income tax benefit of
$61.1 million
and a corresponding
$61.1 million
decrease in net deferred tax liabilities as of
December 31, 2017
. We believe the accounting for the effects of H.R.1 recognized in the
December 31, 2017
financial statements is materially complete. However, evolving analyses and interpretations of the law may cause a change to the amounts presented. Any such changes that may arise will be recognized in the period determined, but no later than
December 31, 2018
. As a result of H.R.1, we expect our effective tax rate in future periods will be lower than in periods prior to enactment. In addition, the limitations on utilization of net operating losses and deductibility of interest and executive compensation may result in the payment of cash taxes earlier than expected.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of net deferred taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
Assets:
|
|
|
|
|
|
|
Stock compensation and other accrued amounts
|
|
$
|
31,044
|
|
|
$
|
58,306
|
|
Net operating loss carryforward, net of valuation allowance
|
|
313,738
|
|
|
399,912
|
|
Credit carryforward
|
|
3,995
|
|
|
6,016
|
|
|
|
348,777
|
|
|
464,234
|
|
Liabilities:
|
|
|
|
|
|
|
Property, plant and equipment
|
|
(450,395
|
)
|
|
(408,399
|
)
|
Net deferred tax (liabilities) assets
|
|
$
|
(101,618
|
)
|
|
$
|
55,835
|
|
At
December 31, 2017
, we had a U.S. net tax operating loss carryforward of approximately
$1,377.7 million
, which would expire in years
2031
through
2037
. We believe that the carryforward will be utilized before it expires. We recorded a
$3.5 million
increase to the net operating loss carryforward at
December 31, 2017
, for certain state losses and a corresponding increase in the state net operating loss valuation allowance of
$4.0 million
. The net decrease in the state net operating losses after reduction for the valuation allowance was
$0.5 million
. The total valuation allowance on state net operating losses at
December 31, 2017
was
$103.7 million
because it is not more likely than not that these additional state net operating losses will be utilized before they expire. There are no other valuation allowances. We also had an alternative minimum tax credit carryforward of approximately
$3.0 million
and enhanced oil recovery and marginal well credits of
$0.9 million
.
At
December 31, 2017
and
2016
, we had
no
unrecognized tax benefits that would impact our effective rate and we have made
no
provisions for interest or penalties related to uncertain tax positions. The tax years
2014
through
2016
remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open to examination for tax years
2013
through
2016
. We do not anticipate the need for any significant income tax payments in the near term.
10. COMMITMENTS AND CONTINGENCIES
Lease Commitments
We have various commitments for office space under operating lease arrangements. During the years ended
December 31, 2017
,
2016
, and
2015
, rent expense for these operating leases approximated
$13.1 million
,
$12.9 million
, and
$13.2 million
, respectively.
Shown below are future minimum cash payments required under these leases as of
December 31, 2017
.
|
|
|
|
|
|
(in thousands)
|
|
|
2018
|
|
$
|
9,742
|
|
2019
|
|
10,702
|
|
2020
|
|
10,836
|
|
2021
|
|
11,053
|
|
2022
|
|
11,222
|
|
Later years
|
|
32,645
|
|
Total future minimum lease payments
|
|
$
|
86,200
|
|
We have various commitments for compressor equipment under operating lease arrangements totaling
$8.5 million
with lease terms expiring in the next
2
-
24 months
.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Commitments
At
December 31, 2017
, we had estimated commitments of approximately: (i)
$252.6 million
to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii)
$33.3 million
to finish gathering system construction in progress.
At
December 31, 2017
, we had firm sales contracts to deliver approximately
217.6
Bcf of gas over the next
7.1 years
. If we do not deliver this gas, our estimated financial commitment, calculated using the January 2018 index price, would be approximately
$476.7 million
. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.
In connection with gas gathering and processing agreements, we have volume commitments over the next
8.3 years
. If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of
December 31, 2017
, would be approximately
$298.3 million
. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.
We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of
December 31, 2017
, would be approximately
$11.4 million
. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.
At
December 31, 2017
, we have various firm transportation agreements for pipeline capacity with end dates ranging from 2018 - 2025 under which we will have to pay an estimated
$36.5 million
over the remaining terms of the agreements. These agreements were entered into to support our residue marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation.
All of the noted commitments were routine and made in the normal course of our business.
Litigation
In the normal course of business, we are involved with various litigation matters. When a loss contingency exists, we assess whether it is probable that an asset has been impaired or a liability has been incurred and, if so, we determine if the amount of loss can be reasonably estimated, all in accordance with guidance established by the FASB, and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them, we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.
H.B. Krug, et al. v.
Helmerich & Payne, Inc.
In 2008, we recorded litigation expense of
$119.6 million
for the
H.B. Krug, et al. v. Helmerich & Payne, Inc.
trial court verdict, and began accruing additional post-judgment interest and costs for this case.
On December 31, 2013, the Oklahoma Supreme Court reversed the trial court’s
$119.6 million
verdict and affirmed an alternative jury verdict for
$3.65 million
. The Supreme Court also remanded the case back to the trial court for consideration of potential prejudgment interest, attorney’s fees, and cost awards. Accordingly, on December 31, 2013 we reduced the previously recognized litigation expense, which included related interest and costs, and the associated long-term liability by
$142.8 million
.
On April 1, 2014, Cimarex paid the Plaintiffs
$15.8 million
in satisfaction of the
$3.65 million
damages award, the post-judgment interest award, and the payment in lieu of bond, all of which are now final and not appealable. On June 24, 2014, the trial court ruled the Plaintiffs were not entitled to prejudgment interest but were entitled to attorney’s fees and costs, the amount of which will be determined at a subsequent hearing. On November 3, 2015, the Oklahoma Supreme Court affirmed the trial court’s denial of prejudgment interest. The only remaining issue is the amount of Plaintiffs’ award of attorney’s fees, which is subject to future trial, and appellate court proceedings and, therefore, cannot be determined at this time.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. RELATED PARTY TRANSACTIONS
Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately
$52.6 million
,
$18.3 million
, and
$7.9 million
related to these services during the years ended
December 31, 2017
,
2016
, and
2015
, respectively. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.
12. SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Cash paid during the period for:
|
|
|
|
|
|
|
|
|
|
Interest expense (net of capitalized amounts of $23,113, $20,308, and $28,819, respectively)
|
|
$
|
52,245
|
|
|
$
|
59,282
|
|
|
$
|
51,966
|
|
Income taxes
|
|
$
|
3
|
|
|
$
|
13
|
|
|
$
|
558
|
|
Cash received for income tax refunds
|
|
$
|
111
|
|
|
$
|
1,450
|
|
|
$
|
1,503
|
|
CIMAREX ENERGY CO.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Oil and Gas Reserve Information—
Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (“SEC”).
Reserve definitions comply with definitions of Rule 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by our internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our company’s Vice President of Corporate Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than
23
years of practical experience in reserve evaluation. He has been directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in his current role for the past
13
years.
DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewed reserves associated with greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of
December 31, 2017
. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over
33
years of experience in oil and gas reservoir studies and reserves evaluations.
Proved reserves are those quantities of oil, gas, and NGLs which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment, and material balance analysis. Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process.
The following table summarizes the trailing twelve-month index prices used in the reserves estimates for
2017
,
2016
, and
2015
. These prices are prior to adjustments for fixed and determinable amounts under provisions in existing contracts, location, grade, and quality.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2017
|
|
2016
|
|
2015
|
Gas price per Mcf
|
$
|
2.98
|
|
|
$
|
2.48
|
|
|
$
|
2.59
|
|
Oil price per Bbl
|
$
|
51.34
|
|
|
$
|
42.75
|
|
|
$
|
50.28
|
|
NGL price per Bbl
|
$
|
19.09
|
|
|
$
|
14.37
|
|
|
$
|
14.41
|
|
CIMAREX ENERGY CO.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following table sets forth our estimates of our proved, proved developed, and proved undeveloped oil, gas, and NGL reserves as of December 31,
2017
,
2016
,
2015
, and
2014
and changes in our proved reserves for the years ended December 31,
2017
,
2016
, and
2015
. All of our proved reserves are located entirely within the U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(MMcf)
|
|
Oil
(MBbls)
|
|
NGL
(MBbls)
|
|
Total
(MMcfe)
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
1,666,733
|
|
|
118,992
|
|
|
125,273
|
|
|
3,132,323
|
|
Revisions of previous estimates
|
(154,390
|
)
|
|
(14,633
|
)
|
|
(5,668
|
)
|
|
(276,192
|
)
|
Extensions and discoveries
|
183,084
|
|
|
22,859
|
|
|
18,079
|
|
|
428,714
|
|
Purchases of reserves
|
15
|
|
|
1
|
|
|
1
|
|
|
25
|
|
Production
|
(168,987
|
)
|
|
(18,663
|
)
|
|
(13,063
|
)
|
|
(359,343
|
)
|
Sales of reserves
|
(9,503
|
)
|
|
(758
|
)
|
|
(345
|
)
|
|
(16,120
|
)
|
December 31, 2015
|
1,516,952
|
|
|
107,798
|
|
|
124,277
|
|
|
2,909,407
|
|
Revisions of previous estimates
|
5,888
|
|
|
(4,357
|
)
|
|
6,670
|
|
|
19,761
|
|
Extensions and discoveries
|
123,175
|
|
|
19,419
|
|
|
14,050
|
|
|
323,987
|
|
Purchases of reserves
|
959
|
|
|
1
|
|
|
—
|
|
|
965
|
|
Production
|
(168,227
|
)
|
|
(16,528
|
)
|
|
(14,200
|
)
|
|
(352,591
|
)
|
Sales of reserves
|
(7,327
|
)
|
|
(455
|
)
|
|
(164
|
)
|
|
(11,042
|
)
|
December 31, 2016
|
1,471,420
|
|
|
105,878
|
|
|
130,633
|
|
|
2,890,487
|
|
Revisions of previous estimates
|
(39,749
|
)
|
|
(1,225
|
)
|
|
(2,099
|
)
|
|
(59,706
|
)
|
Extensions and discoveries
|
363,774
|
|
|
53,464
|
|
|
42,692
|
|
|
940,714
|
|
Purchases of reserves
|
642
|
|
|
42
|
|
|
78
|
|
|
1,363
|
|
Production
|
(187,468
|
)
|
|
(20,861
|
)
|
|
(17,374
|
)
|
|
(416,875
|
)
|
Sales of reserves
|
(984
|
)
|
|
(60
|
)
|
|
(70
|
)
|
|
(1,761
|
)
|
December 31, 2017
|
1,607,635
|
|
|
137,238
|
|
|
153,860
|
|
|
3,354,222
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
1,263,957
|
|
|
100,050
|
|
|
89,630
|
|
|
2,402,033
|
|
December 31, 2015
|
1,129,490
|
|
|
89,189
|
|
|
87,549
|
|
|
2,189,920
|
|
December 31, 2016
|
1,144,720
|
|
|
92,032
|
|
|
99,176
|
|
|
2,291,966
|
|
December 31, 2017
|
1,334,510
|
|
|
114,116
|
|
|
126,227
|
|
|
2,776,565
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
402,776
|
|
|
18,942
|
|
|
35,643
|
|
|
730,290
|
|
December 31, 2015
|
387,462
|
|
|
18,609
|
|
|
36,728
|
|
|
719,487
|
|
December 31, 2016
|
326,700
|
|
|
13,846
|
|
|
31,457
|
|
|
598,521
|
|
December 31, 2017
|
273,125
|
|
|
23,122
|
|
|
27,633
|
|
|
577,657
|
|
Year-end
2017
proved reserves
increased
approximately
16%
from year-end
2016
proved reserves, to
3.35
Tcfe. Proved natural gas reserves were
1.61
Tcf, proved oil reserves were
0.82
Tcfe, and proved NGL reserves were
0.92
Tcfe. Our reserves in the Mid-Continent accounted for
52%
of total proved reserves, with nearly all of the remainder in the Permian Basin.
During
2017
, we added
940.7
Bcfe of proved reserves through extensions and discoveries, primarily in the Mid-Continent and Permian Basin where we added
282.9
Bcfe and
657.8
Bcfe, respectively. In addition, we had net negative revisions of
59.7
Bcfe. The revisions included decreases of
248.8
Bcfe for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure and
43.9
Bcfe related to increases in operating expenses. These decreases were partially offset by increases of
187.2
Bcfe in price-related revisions and
45.8
Bcfe of net technical revisions related primarily to better than expected performance from wells with initial production in late
2016
.
CIMAREX ENERGY CO.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
During
2016
, we added
324.0
Bcfe of proved reserves through extensions and discoveries, primarily in the Mid-Continent and Permian Basin where we added
121.6
Bcfe and
198.7
Bcfe, respectively. In addition, we had net positive revisions of
19.8
Bcfe. The revisions included increases of
126.2
Bcfe for net performance revisions and
138.5
Bcfe related to decreases in operating expenses, partially offset by negative revisions of
244.9
Bcfe due to lower commodity prices. The performance revisions resulted primarily from positive adjustments to previously booked PUD reserves (
72.3
Bcfe) and better than expected performance from wells with initial production in late
2015
.
During
2015
, we added
428.7
Bcfe of proved reserves through extensions and discoveries, primarily in the Mid-Continent and Permian Basin, where we added
176.8
Bcfe and
251.1
Bcfe, respectively. During
2015
, we had net negative reserve revisions of
276.2
Bcfe. The significant decrease in commodity prices seen in
2015
resulted in negative revisions of
398.8
Bcfe due to prices. In addition,
19.1
Bcfe of negative revisions were due to increases in operating expenses, which shortened the economic lives of properties. These decreases were partially offset by net positive performance revisions of
141.7
Bcfe, which included
47.4
Bcfe for better than expected performance of PUD reserves converted to proved developed reserves during the year and positive adjustments of
95.3
Bcfe to previously booked PUD reserves.
At
December 31, 2017
, we had PUD reserves of
577.7
Bcfe, down
20.8
Bcfe, or
3%
, from
598.5
Bcfe of PUD reserves at
December 31, 2016
. Changes in our PUD reserves are summarized in the table below (in Bcfe).
|
|
|
|
PUD reserves at December 31, 2016
|
598.5
|
|
Converted to developed
|
(61.1
|
)
|
Additions
|
307.3
|
|
Net revisions
|
(267.0
|
)
|
PUD reserves at December 31, 2017
|
577.7
|
|
During
2017
, we invested
$69.5 million
to develop and convert
10%
of our
2016
PUD reserves to proved developed reserves. During
2016
, we invested
$108.8 million
to develop PUD reserves, converting
14%
of our
2015
PUD reserves to proved developed reserves. During
2015
, we invested
$246.5 million
to develop PUD reserves, converting
24%
of our
2014
PUD reserves to proved developed reserves.
During
2017
,
234.4
Bcfe, or
76%
, of our
307.3
Bcfe of PUD reserve additions occurred in the Permian Basin, while the remainder of the additions were in our western Oklahoma Cana area. At
December 31, 2017
,
41%
of our PUD reserves were in the Permian Basin, while the remainder were in our western Oklahoma Cana area. We have no PUD reserves that have remained undeveloped for five years or more after initial disclosure and we have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial disclosure.
During
2017
, we had net negative PUD reserve revisions of
267.0
Bcfe. Of this total,
248.8
Bcfe was for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure. The remaining 18.2 Bcfe of net negative adjustments was comprised of negative technical revisions of
20.1
Bcfe to remaining previously booked PUD reserves and
4.5
Bcfe of negative revisions from higher projected operating expenses that were partially offset by
6.4
Bcfe of positive price-related revisions.
CIMAREX ENERGY CO.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Costs Incurred—
The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Costs incurred during the year:
|
|
|
|
|
|
|
|
|
|
Acquisition of properties
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
938
|
|
|
$
|
2,678
|
|
|
$
|
30
|
|
Unproved
|
|
135,565
|
|
|
67,961
|
|
|
41,233
|
|
Exploration
|
|
11,804
|
|
|
5,814
|
|
|
6,902
|
|
Development
|
|
1,140,548
|
|
|
672,842
|
|
|
823,830
|
|
Oil and gas expenditures
|
|
1,288,855
|
|
|
749,295
|
|
|
871,995
|
|
Property sales
|
|
(11,680
|
)
|
|
(24,687
|
)
|
|
(41,276
|
)
|
|
|
1,277,175
|
|
|
724,608
|
|
|
830,719
|
|
Asset retirement obligation, net
|
|
9,416
|
|
|
(7,950
|
)
|
|
(4,818
|
)
|
|
|
$
|
1,286,591
|
|
|
$
|
716,658
|
|
|
$
|
825,901
|
|
Aggregate Capitalized Costs—
The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at
December 31, 2017
.
|
|
|
|
|
|
(in thousands)
|
|
|
Proved properties
|
|
$
|
17,513,460
|
|
Unproved properties and properties under development, not being amortized
|
|
476,903
|
|
|
|
17,990,363
|
|
Less-accumulated depreciation, depletion, amortization, and impairments
|
|
(14,748,833
|
)
|
Net oil and gas properties
|
|
$
|
3,241,530
|
|
Costs Not Being Amortized—
The following table summarizes oil and gas property costs not being amortized at
December 31, 2017
, by year that the costs were incurred.
|
|
|
|
|
|
(in thousands)
|
|
|
2017
|
|
$
|
266,124
|
|
2016
|
|
53,076
|
|
2015
|
|
32,592
|
|
2014 and prior
|
|
125,111
|
|
|
|
$
|
476,903
|
|
Of the costs not being amortized,
$140.0 million
(
29%
) relates to unevaluated wells in progress and
$47.7 million
(
10%
) is capitalized interest. The remaining
$289.2 million
(
61%
) is for land and seismic expenditures, most of which were for costs invested in our Mid-Continent region (
$104.6 million
) and our Permian Basin region (
$169.1 million
). On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors. We expect to include these costs in the amortization computation as we continue with our exploration and development plans.
CIMAREX ENERGY CO.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Oil and Gas Operations—
The following table contains direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax expense related to our oil and gas operations is computed using the effective tax rate for the period, with the 2017 effective tax rate adjusted to remove the impact of the reduction in the federal statutory rate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands, except per Mcfe)
|
|
2017
|
|
2016
|
|
2015
|
Oil, gas, and NGL revenues from production
|
|
$
|
1,874,003
|
|
|
$
|
1,221,218
|
|
|
$
|
1,417,538
|
|
Less operating costs and income taxes:
|
|
|
|
|
|
|
|
|
|
Impairment of oil and gas properties
|
|
—
|
|
|
757,670
|
|
|
4,033,295
|
|
Depletion
|
|
399,328
|
|
|
346,003
|
|
|
689,120
|
|
Asset retirement obligation
|
|
15,624
|
|
|
7,828
|
|
|
9,121
|
|
Production
|
|
262,180
|
|
|
232,002
|
|
|
299,374
|
|
Transportation, processing, and other operating
|
|
254,730
|
|
|
210,144
|
|
|
183,134
|
|
Taxes other than income
|
|
89,864
|
|
|
61,946
|
|
|
84,764
|
|
Income tax expense (benefit)
|
|
310,937
|
|
|
(135,665
|
)
|
|
(1,410,065
|
)
|
|
|
1,332,663
|
|
|
1,479,928
|
|
|
3,888,743
|
|
Results of operations from oil and gas producing activities
|
|
$
|
541,340
|
|
|
$
|
(258,710
|
)
|
|
$
|
(2,471,205
|
)
|
Depletion rate per Mcfe
|
|
$
|
0.96
|
|
|
$
|
0.98
|
|
|
$
|
1.92
|
|
Standardized Measure of Future Net Cash Flows—
The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (“Standardized Measure”) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, varying price and cost assumptions, and risks inherent in reserve estimates.
Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.
The following summary sets forth our Standardized Measure.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Future cash inflows
|
|
$
|
11,967,325
|
|
|
$
|
7,576,211
|
|
|
$
|
8,839,485
|
|
Future production costs
|
|
(4,360,599
|
)
|
|
(2,970,891
|
)
|
|
(3,521,881
|
)
|
Future development costs
|
|
(948,735
|
)
|
|
(794,298
|
)
|
|
(1,058,020
|
)
|
Future income tax expenses
|
|
(882,519
|
)
|
|
(507,145
|
)
|
|
(728,029
|
)
|
Future net cash flows
|
|
5,775,472
|
|
|
3,303,877
|
|
|
3,531,555
|
|
10% annual discount for estimated timing of cash flows
|
|
(2,490,471
|
)
|
|
(1,411,259
|
)
|
|
(1,597,424
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
3,285,001
|
|
|
$
|
1,892,618
|
|
|
$
|
1,934,131
|
|
CIMAREX ENERGY CO.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The estimates of cash flows shown above are based upon the unweighted trailing twelve-month average first-day-of-the-month benchmark prices. See table above under
Oil and Gas Reserve Information
for prices used in determining the Standardized Measure. If future gas sales are covered by contracts at specified prices, the contract prices would be used. Prices are market driven and will fluctuate due to supply and demand factors, seasonality, and geopolitical and economic factors.
The following are the principal sources of change in the Standardized Measure.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Standardized Measure, beginning of period
|
|
$
|
1,892,618
|
|
|
$
|
1,934,131
|
|
|
$
|
4,352,845
|
|
Sales, net of production costs
|
|
(1,267,229
|
)
|
|
(717,126
|
)
|
|
(850,267
|
)
|
Net change in sales prices, net of production costs
|
|
855,024
|
|
|
(429,956
|
)
|
|
(4,262,261
|
)
|
Extensions and discoveries, net of future production and development costs
|
|
1,443,577
|
|
|
517,702
|
|
|
573,373
|
|
Changes in future development costs
|
|
298,819
|
|
|
167,387
|
|
|
280,163
|
|
Previously estimated development costs incurred during the period
|
|
78,398
|
|
|
110,945
|
|
|
214,749
|
|
Revision of quantity estimates
|
|
(65,376
|
)
|
|
15,701
|
|
|
(240,063
|
)
|
Accretion of discount
|
|
212,192
|
|
|
227,904
|
|
|
638,948
|
|
Change in income taxes
|
|
(210,519
|
)
|
|
115,609
|
|
|
1,691,721
|
|
Purchases of reserves in place
|
|
2,255
|
|
|
429
|
|
|
20
|
|
Sales of reserves
|
|
(1,666
|
)
|
|
(9,440
|
)
|
|
(26,225
|
)
|
Change in production rates and other
|
|
46,908
|
|
|
(40,668
|
)
|
|
(438,872
|
)
|
Standardized Measure, end of period
|
|
$
|
3,285,001
|
|
|
$
|
1,892,618
|
|
|
$
|
1,934,131
|
|
CIMAREX ENERGY CO.
SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
2017
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
447,176
|
|
|
$
|
456,452
|
|
|
$
|
463,681
|
|
|
$
|
550,940
|
|
Expenses, net
|
|
316,204
|
|
|
359,190
|
|
|
372,282
|
|
|
376,244
|
|
Net income
|
|
$
|
130,972
|
|
|
$
|
97,262
|
|
|
$
|
91,399
|
|
|
$
|
174,696
|
|
Earnings per share to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.38
|
|
|
$
|
1.02
|
|
|
$
|
0.96
|
|
|
$
|
1.83
|
|
Diluted
|
|
$
|
1.38
|
|
|
$
|
1.02
|
|
|
$
|
0.96
|
|
|
$
|
1.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
2016
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
240,600
|
|
|
$
|
298,873
|
|
|
$
|
335,717
|
|
|
$
|
382,155
|
|
Expenses, net (1)
|
|
472,059
|
|
|
513,327
|
|
|
346,390
|
|
|
334,372
|
|
Net (loss) income
|
|
$
|
(231,459
|
)
|
|
$
|
(214,454
|
)
|
|
$
|
(10,673
|
)
|
|
$
|
47,783
|
|
Earnings (loss) per share to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(2.49
|
)
|
|
$
|
(2.31
|
)
|
|
$
|
(0.12
|
)
|
|
$
|
0.50
|
|
Diluted
|
|
$
|
(2.49
|
)
|
|
$
|
(2.31
|
)
|
|
$
|
(0.12
|
)
|
|
$
|
0.50
|
|
________________________________________
|
|
(1)
|
The 2016 quarterly expenses, net include non-cash impairments to our oil and gas properties of
$318.8 million
(or
$3.43
per diluted share),
$333.3 million
(or
$3.58
per diluted share), and
$105.6 million
(or
$1.13
per diluted share) for the first quarter through the third quarter of 2016, respectively, as discussed in Note 1 to the Consolidated Financial Statements under
Oil and Gas Properties
.
|
The sum of the individual quarterly earnings (loss) per common share amounts may not agree with year-to-date earnings (loss) per common share because each quarter’s computation is based on the number of shares outstanding at the end of the applicable quarter using the two-class method.