Delaware
(State or other jurisdiction
of incorporation or organization)
|
|
41-0518430
(I.R.S. Employer
Identification No.)
|
1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
|
|
80203
(Zip Code)
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PAGE
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June 30,
2018 |
|
December 31,
2017 |
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
615,906
|
|
|
$
|
313,943
|
|
Accounts receivable
|
178,682
|
|
|
160,154
|
|
||
Derivative assets
|
146,329
|
|
|
64,266
|
|
||
Prepaid expenses and other
|
14,293
|
|
|
10,752
|
|
||
Total current assets
|
955,210
|
|
|
549,115
|
|
||
Property and equipment (successful efforts method):
|
|
|
|
||||
Proved oil and gas properties
|
6,372,956
|
|
|
6,139,379
|
|
||
Accumulated depletion, depreciation, and amortization
|
(3,041,653
|
)
|
|
(3,171,575
|
)
|
||
Unproved oil and gas properties
|
1,917,883
|
|
|
2,047,203
|
|
||
Wells in progress
|
361,238
|
|
|
321,347
|
|
||
Oil and gas properties held for sale, net
|
5,040
|
|
|
111,700
|
|
||
Other property and equipment, net of accumulated depreciation of $53,483 and $49,985, respectively
|
102,986
|
|
|
106,738
|
|
||
Total property and equipment, net
|
5,718,450
|
|
|
5,554,792
|
|
||
Noncurrent assets:
|
|
|
|
||||
Derivative assets
|
31,151
|
|
|
40,362
|
|
||
Other noncurrent assets
|
31,674
|
|
|
32,507
|
|
||
Total noncurrent assets
|
62,825
|
|
|
72,869
|
|
||
Total assets
|
$
|
6,736,485
|
|
|
$
|
6,176,776
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses
|
$
|
446,318
|
|
|
$
|
386,630
|
|
Current portion of Senior Notes, net of unamortized deferred financing costs (note 5)
|
342,301
|
|
|
—
|
|
||
Derivative liabilities
|
259,338
|
|
|
172,582
|
|
||
Total current liabilities
|
1,047,957
|
|
|
559,212
|
|
||
Noncurrent liabilities:
|
|
|
|
||||
Revolving credit facility
|
—
|
|
|
—
|
|
||
Noncurrent portion of Senior Notes, net of unamortized deferred financing costs
|
2,429,994
|
|
|
2,769,663
|
|
||
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
143,430
|
|
|
139,107
|
|
||
Asset retirement obligations
|
87,279
|
|
|
103,026
|
|
||
Asset retirement obligations associated with oil and gas properties held for sale
|
—
|
|
|
11,369
|
|
||
Deferred income taxes
|
177,709
|
|
|
79,989
|
|
||
Derivative liabilities
|
67,583
|
|
|
71,402
|
|
||
Other noncurrent liabilities
|
45,906
|
|
|
48,400
|
|
||
Total noncurrent liabilities
|
2,951,901
|
|
|
3,222,956
|
|
||
|
|
|
|
||||
Commitments and contingencies (note 6)
|
|
|
|
|
|
||
|
|
|
|
||||
Stockholders
’
equity:
|
|
|
|
||||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,846,998 and 111,687,016 shares, respectively
|
1,118
|
|
|
1,117
|
|
||
Additional paid-in capital
|
1,754,169
|
|
|
1,741,623
|
|
||
Retained earnings
(1)
|
997,641
|
|
|
665,657
|
|
||
Accumulated other comprehensive loss
(1)
|
(16,301
|
)
|
|
(13,789
|
)
|
||
Total stockholders
’
equity
|
2,736,627
|
|
|
2,394,608
|
|
||
Total liabilities and stockholders
’
equity
|
$
|
6,736,485
|
|
|
$
|
6,176,776
|
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
|
|
(as adjusted)
|
|
|
|
(as adjusted)
|
||||||||
Operating revenues and other income:
|
|
|
|
|
|
|
|
||||||||
Oil, gas, and NGL production revenue
|
$
|
402,558
|
|
|
$
|
284,939
|
|
|
$
|
785,444
|
|
|
$
|
618,137
|
|
Net gain (loss) on divestiture activity
|
39,501
|
|
|
(167,133
|
)
|
|
424,870
|
|
|
(129,670
|
)
|
||||
Other operating revenues
|
1,857
|
|
|
2,915
|
|
|
3,197
|
|
|
4,992
|
|
||||
Total operating revenues and other income
|
443,916
|
|
|
120,721
|
|
|
1,213,511
|
|
|
493,459
|
|
||||
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil, gas, and NGL production expense
|
117,400
|
|
|
124,376
|
|
|
238,279
|
|
|
262,422
|
|
||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
151,765
|
|
|
153,232
|
|
|
282,238
|
|
|
291,044
|
|
||||
Exploration
|
14,056
|
|
|
12,983
|
|
|
27,783
|
|
|
24,800
|
|
||||
Abandonment and impairment of unproved properties
|
11,935
|
|
|
157
|
|
|
17,560
|
|
|
157
|
|
||||
General and administrative
|
28,920
|
|
|
28,237
|
|
|
56,602
|
|
|
57,054
|
|
||||
Net derivative (gain) loss
|
63,749
|
|
|
(55,189
|
)
|
|
71,278
|
|
|
(169,963
|
)
|
||||
Other operating expenses, net
|
(57
|
)
|
|
4,251
|
|
|
4,555
|
|
|
9,110
|
|
||||
Total operating expenses
|
387,768
|
|
|
268,047
|
|
|
698,295
|
|
|
474,624
|
|
||||
Income (loss) from operations
|
56,148
|
|
|
(147,326
|
)
|
|
515,216
|
|
|
18,835
|
|
||||
Interest expense
|
(41,654
|
)
|
|
(44,595
|
)
|
|
(84,739
|
)
|
|
(91,548
|
)
|
||||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(35
|
)
|
||||
Other non-operating income, net
|
1,802
|
|
|
953
|
|
|
2,211
|
|
|
720
|
|
||||
Income (loss) before income taxes
|
16,296
|
|
|
(190,968
|
)
|
|
432,688
|
|
|
(72,028
|
)
|
||||
Income tax (expense) benefit
|
901
|
|
|
71,061
|
|
|
(98,090
|
)
|
|
26,555
|
|
||||
Net income (loss)
|
$
|
17,197
|
|
|
$
|
(119,907
|
)
|
|
$
|
334,598
|
|
|
$
|
(45,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic weighted-average common shares outstanding
|
111,701
|
|
|
111,277
|
|
|
111,698
|
|
|
111,274
|
|
||||
Diluted weighted-average common shares outstanding
|
113,630
|
|
|
111,277
|
|
|
113,267
|
|
|
111,274
|
|
||||
Basic net income (loss) per common share
|
$
|
0.15
|
|
|
$
|
(1.08
|
)
|
|
$
|
3.00
|
|
|
$
|
(0.41
|
)
|
Diluted net income (loss) per common share
|
$
|
0.15
|
|
|
$
|
(1.08
|
)
|
|
$
|
2.95
|
|
|
$
|
(0.41
|
)
|
Dividends per common share
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
|
||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net income (loss)
|
$
|
17,197
|
|
|
$
|
(119,907
|
)
|
|
$
|
334,598
|
|
|
$
|
(45,473
|
)
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
||||||||
Pension liability adjustment
|
198
|
|
|
124
|
|
|
458
|
|
|
(443
|
)
|
||||
Total other comprehensive income (loss), net of tax
|
198
|
|
|
124
|
|
|
458
|
|
|
(443
|
)
|
||||
Total comprehensive income (loss)
|
$
|
17,395
|
|
|
$
|
(119,783
|
)
|
|
$
|
335,056
|
|
|
$
|
(45,916
|
)
|
|
For the Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
|
(as adjusted)
|
||||
Cash flows from operating activities:
|
|
|
|
||||
Net income (loss)
|
$
|
334,598
|
|
|
$
|
(45,473
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
||||
Net (gain) loss on divestiture activity
|
(424,870
|
)
|
|
129,670
|
|
||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
282,238
|
|
|
291,044
|
|
||
Abandonment and impairment of unproved properties
|
17,560
|
|
|
157
|
|
||
Stock-based compensation expense
|
10,676
|
|
|
9,813
|
|
||
Net derivative (gain) loss
|
71,278
|
|
|
(169,963
|
)
|
||
Derivative settlement gain (loss)
|
(61,193
|
)
|
|
16,310
|
|
||
Amortization of debt discount and deferred financing costs
|
7,750
|
|
|
8,679
|
|
||
Loss on extinguishment of debt
|
—
|
|
|
35
|
|
||
Deferred income taxes
|
97,505
|
|
|
(30,790
|
)
|
||
Other, net
|
(2,302
|
)
|
|
4,464
|
|
||
Net change in working capital
|
(21,722
|
)
|
|
28,182
|
|
||
Net cash provided by operating activities
|
311,518
|
|
|
242,128
|
|
||
|
|
|
|
||||
Cash flows from investing activities:
|
|
|
|
||||
Net proceeds from the sale of oil and gas properties
|
742,215
|
|
|
766,247
|
|
||
Capital expenditures
|
(723,319
|
)
|
|
(366,743
|
)
|
||
Acquisition of proved and unproved oil and gas properties
|
(24,615
|
)
|
|
(88,140
|
)
|
||
Net cash provided by (used in) investing activities
|
(5,719
|
)
|
|
311,364
|
|
||
|
|
|
|
||||
Cash flows from financing activities:
|
|
|
|
||||
Proceeds from credit facility
|
—
|
|
|
406,000
|
|
||
Repayment of credit facility
|
—
|
|
|
(406,000
|
)
|
||
Cash paid to repurchase Senior Notes
|
—
|
|
|
(2,344
|
)
|
||
Cash paid for extinguishment of debt
|
—
|
|
|
(13
|
)
|
||
Net proceeds from sale of common stock
|
1,881
|
|
|
1,738
|
|
||
Dividends paid
|
(5,584
|
)
|
|
(5,563
|
)
|
||
Other, net
|
(133
|
)
|
|
(161
|
)
|
||
Net cash used in financing activities
|
(3,836
|
)
|
|
(6,343
|
)
|
||
|
|
|
|
||||
Net change in cash, cash equivalents, and restricted cash
(1)
|
301,963
|
|
|
547,149
|
|
||
Cash, cash equivalents, and restricted cash at beginning of period
(1)
|
313,943
|
|
|
12,372
|
|
||
Cash, cash equivalents, and restricted cash at end of period
(1)
|
$
|
615,906
|
|
|
$
|
559,521
|
|
(1)
|
Refer to
Note 1 - Summary of Significant Accounting Policies
for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”).
|
|
For the Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
|
(as adjusted)
|
||||
Operating activities:
|
|
|
|
||||
Cash paid for interest, net of capitalized interest
|
$
|
(77,803
|
)
|
|
$
|
(83,493
|
)
|
Net cash (paid) refunded for income taxes
|
$
|
207
|
|
|
$
|
(8,220
|
)
|
|
|
|
|
||||
Investing activities:
|
|
|
|
||||
Changes in capital expenditure accruals and other
|
$
|
62,167
|
|
|
$
|
44,770
|
|
|
|
|
|
||||
Supplemental non-cash investing activities:
|
|
|
|
||||
Carrying value of properties exchanged
|
$
|
—
|
|
|
$
|
279,750
|
|
|
|
|
|
||||
Supplemental non-cash financing activities:
|
|
|
|
||||
Non-cash loss on extinguishment of debt, net
|
$
|
—
|
|
|
$
|
22
|
|
|
For the Six Months Ended June 30, 2017
|
||||||
|
As Reported
|
|
As Adjusted
|
||||
|
(in thousands)
|
||||||
Cash flows from operating activities:
|
|
|
|
||||
Non-cash (gain) loss on extinguishment of debt, net
|
$
|
22
|
|
|
N/A
|
|
|
Loss on extinguishment of debt
|
N/A
|
|
|
$
|
35
|
|
|
Net cash provided by operating activities
|
$
|
242,115
|
|
|
$
|
242,128
|
|
|
|
|
|
||||
Cash flows from investing activities:
|
|
|
|
||||
Other, net
|
$
|
3,000
|
|
|
N/A
|
|
|
Net cash provided by (used in) investing activities
|
$
|
314,364
|
|
|
$
|
311,364
|
|
|
|
|
|
||||
Cash flows from financing activities:
|
|
|
|
||||
Cash paid for extinguishment of debt
|
N/A
|
|
|
$
|
(13
|
)
|
|
Net cash used in financing activities
|
$
|
(6,330
|
)
|
|
$
|
(6,343
|
)
|
|
|
|
|
||||
Net change in cash and cash equivalents
|
$
|
550,149
|
|
|
N/A
|
|
|
Net change in cash, cash equivalents, and restricted cash
|
N/A
|
|
|
$
|
547,149
|
|
|
Cash and cash equivalents at beginning of period
|
$
|
9,372
|
|
|
N/A
|
|
|
Cash, cash equivalents, and restricted cash at beginning of period
|
N/A
|
|
|
$
|
12,372
|
|
|
Cash and cash equivalents at end of period
|
$
|
559,521
|
|
|
N/A
|
|
|
Cash, cash equivalents, and restricted cash at end of period
|
N/A
|
|
|
$
|
559,521
|
|
|
As of June 30, 2018
|
|
As of December 31, 2017
|
||||
|
(in thousands)
|
||||||
Cash and cash equivalents
|
$
|
615,906
|
|
|
$
|
313,943
|
|
Restricted cash
|
—
|
|
|
—
|
|
||
Total cash, cash equivalents, and restricted cash
|
$
|
615,906
|
|
|
$
|
313,943
|
|
|
For the Three Months Ended June 30, 2017
|
|
For the Six Months Ended June 30, 2017
|
||||||||||||
|
As Reported
|
|
As Adjusted
|
|
As Reported
|
|
As Adjusted
|
||||||||
|
(in thousands)
|
||||||||||||||
Operating expenses:
|
|
|
|
|
|
|
|
||||||||
Exploration
|
$
|
13,072
|
|
|
$
|
12,983
|
|
|
$
|
25,050
|
|
|
$
|
24,800
|
|
General and administrative
|
$
|
28,460
|
|
|
$
|
28,237
|
|
|
$
|
57,684
|
|
|
$
|
57,054
|
|
Total operating expenses
|
$
|
268,359
|
|
|
$
|
268,047
|
|
|
$
|
475,504
|
|
|
$
|
474,624
|
|
|
|
|
|
|
|
|
|
||||||||
Income (loss) from operations
|
$
|
(147,638
|
)
|
|
$
|
(147,326
|
)
|
|
$
|
17,955
|
|
|
$
|
18,835
|
|
|
|
|
|
|
|
|
|
||||||||
Other non-operating income, net
|
$
|
1,265
|
|
|
$
|
953
|
|
|
$
|
1,600
|
|
|
$
|
720
|
|
|
Permian
|
|
South Texas & Gulf Coast
|
|
Rocky Mountain
|
|
Total
|
||||||||||||||||||||||||
|
Three Months Ended June 30,
|
|
Three Months Ended June 30,
|
|
Three Months Ended June 30,
|
|
Three Months Ended June 30,
|
||||||||||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||||||
Oil, gas, and NGL production revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Oil production revenue
|
$
|
227,636
|
|
|
$
|
78,554
|
|
|
$
|
19,346
|
|
|
$
|
13,072
|
|
|
$
|
19,168
|
|
|
$
|
37,248
|
|
|
$
|
266,150
|
|
|
$
|
128,874
|
|
Gas production revenue
|
31,734
|
|
|
12,937
|
|
|
52,235
|
|
|
87,760
|
|
|
95
|
|
|
1,043
|
|
|
84,064
|
|
|
101,740
|
|
||||||||
NGL production revenue
|
129
|
|
|
107
|
|
|
52,248
|
|
|
53,558
|
|
|
(33
|
)
|
|
660
|
|
|
52,344
|
|
|
54,325
|
|
||||||||
Total
|
$
|
259,499
|
|
|
$
|
91,598
|
|
|
$
|
123,829
|
|
|
$
|
154,390
|
|
|
$
|
19,230
|
|
|
$
|
38,951
|
|
|
$
|
402,558
|
|
|
$
|
284,939
|
|
Relative percentage
|
64
|
%
|
|
32
|
%
|
|
31
|
%
|
|
54
|
%
|
|
5
|
%
|
|
14
|
%
|
|
100
|
%
|
|
100
|
%
|
|
Permian
|
|
South Texas & Gulf Coast
|
|
Rocky Mountain
|
|
Total
|
||||||||||||||||||||||||
|
Six Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||||||
Oil, gas, and NGL production revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Oil production revenue
|
$
|
433,430
|
|
|
$
|
160,053
|
|
|
$
|
38,929
|
|
|
$
|
51,936
|
|
|
$
|
54,851
|
|
|
$
|
84,509
|
|
|
$
|
527,210
|
|
|
$
|
296,498
|
|
Gas production revenue
|
56,611
|
|
|
24,246
|
|
|
104,968
|
|
|
175,961
|
|
|
1,594
|
|
|
2,714
|
|
|
163,173
|
|
|
202,921
|
|
||||||||
NGL production revenue
|
253
|
|
|
254
|
|
|
94,018
|
|
|
116,915
|
|
|
790
|
|
|
1,549
|
|
|
95,061
|
|
|
118,718
|
|
||||||||
Total
|
$
|
490,294
|
|
|
$
|
184,553
|
|
|
$
|
237,915
|
|
|
$
|
344,812
|
|
|
$
|
57,235
|
|
|
$
|
88,772
|
|
|
$
|
785,444
|
|
|
$
|
618,137
|
|
Relative percentage
|
63
|
%
|
|
30
|
%
|
|
30
|
%
|
|
56
|
%
|
|
7
|
%
|
|
14
|
%
|
|
100
|
%
|
|
100
|
%
|
1)
|
The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead.
|
2)
|
The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue above and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.
|
3)
|
The Company has certain processing arrangements that include the delivery of unprocessed gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.
|
4)
|
The Company has certain midstream processing arrangements where unprocessed gas is delivered to the inlet of the midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the processed NGLs and residue gas and remits the proceeds to the Company from the sale of the products to third-party customers. In these arrangements, control transfers at the tailgate of the midstream processing facility for both products. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Loss before income taxes
(1)
|
$
|
(17,478
|
)
|
|
$
|
(153,442
|
)
|
|
$
|
(28,975
|
)
|
|
$
|
(486,161
|
)
|
(1)
|
Loss before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity.
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Current portion of income tax (expense) benefit:
|
|
|
|
|
|
|
|
||||||||
Federal
|
$
|
—
|
|
|
$
|
4,607
|
|
|
$
|
—
|
|
|
$
|
(2,832
|
)
|
State
|
40
|
|
|
2,439
|
|
|
(585
|
)
|
|
(1,403
|
)
|
||||
Deferred portion of income tax (expense) benefit
|
861
|
|
|
64,015
|
|
|
(97,505
|
)
|
|
30,790
|
|
||||
Income tax (expense) benefit
|
$
|
901
|
|
|
$
|
71,061
|
|
|
$
|
(98,090
|
)
|
|
$
|
26,555
|
|
Effective tax rate
|
(5.5
|
)%
|
|
37.2
|
%
|
|
22.7
|
%
|
|
36.9
|
%
|
|
As of July 25, 2018
|
|
As of June 30, 2018
|
|
As of December 31, 2017
|
||||||
|
(in thousands)
|
||||||||||
Credit facility balance
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Letters of credit
(2)
|
200
|
|
|
200
|
|
|
200
|
|
|||
Available borrowing capacity
|
999,800
|
|
|
999,800
|
|
|
924,800
|
|
|||
Total aggregate lender commitment amount
|
$
|
1,000,000
|
|
|
$
|
1,000,000
|
|
|
$
|
925,000
|
|
(1)
|
Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled
$2.4 million
and
$3.1 million
as of
June 30, 2018
, and
December 31, 2017
, respectively.
|
(2)
|
Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.
|
|
As of June 30, 2018
|
|
As of December 31, 2017
|
||||||||||||||||||||
|
Principal Amount
|
|
Unamortized Deferred Financing Costs
|
|
Senior Notes, Net of Unamortized Deferred Financing Costs
|
|
Principal Amount
|
|
Unamortized Deferred Financing Costs
|
|
Senior Notes, Net of Unamortized Deferred Financing Costs
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
6.50% Senior Notes due 2021
|
$
|
344,611
|
|
|
$
|
2,310
|
|
|
$
|
342,301
|
|
|
$
|
344,611
|
|
|
$
|
2,656
|
|
|
$
|
341,955
|
|
6.125% Senior Notes due 2022
|
561,796
|
|
|
5,211
|
|
|
556,585
|
|
|
561,796
|
|
|
5,800
|
|
|
555,996
|
|
||||||
6.50% Senior Notes due 2023
|
394,985
|
|
|
3,342
|
|
|
391,643
|
|
|
394,985
|
|
|
3,707
|
|
|
391,278
|
|
||||||
5.0% Senior Notes due 2024
|
500,000
|
|
|
5,149
|
|
|
494,851
|
|
|
500,000
|
|
|
5,610
|
|
|
494,390
|
|
||||||
5.625% Senior Notes due 2025
|
500,000
|
|
|
6,261
|
|
|
493,739
|
|
|
500,000
|
|
|
6,714
|
|
|
493,286
|
|
||||||
6.75% Senior Notes due 2026
|
500,000
|
|
|
6,824
|
|
|
493,176
|
|
|
500,000
|
|
|
7,242
|
|
|
492,758
|
|
||||||
Total
|
$
|
2,801,392
|
|
|
$
|
29,097
|
|
|
$
|
2,772,295
|
|
|
$
|
2,801,392
|
|
|
$
|
31,729
|
|
|
$
|
2,769,663
|
|
|
As of June 30, 2018
|
|
As of December 31, 2017
|
||||
|
(in thousands)
|
||||||
Principal amount of Senior Convertible Notes
|
$
|
172,500
|
|
|
$
|
172,500
|
|
Unamortized debt discount
|
(26,319
|
)
|
|
(30,183
|
)
|
||
Unamortized deferred financing costs
|
(2,751
|
)
|
|
(3,210
|
)
|
||
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
$
|
143,430
|
|
|
$
|
139,107
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Service cost
|
$
|
1,705
|
|
|
$
|
1,269
|
|
|
$
|
3,365
|
|
|
$
|
3,319
|
|
Interest cost
|
637
|
|
|
617
|
|
|
1,310
|
|
|
1,344
|
|
||||
Expected return on plan assets that reduces periodic pension benefit cost
|
(370
|
)
|
|
(563
|
)
|
|
(931
|
)
|
|
(1,122
|
)
|
||||
Amortization of prior service cost
|
5
|
|
|
5
|
|
|
9
|
|
|
9
|
|
||||
Amortization of net actuarial loss
|
340
|
|
|
253
|
|
|
664
|
|
|
649
|
|
||||
Net periodic benefit cost
|
$
|
2,317
|
|
|
$
|
1,581
|
|
|
$
|
4,417
|
|
|
$
|
4,199
|
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Net income (loss)
|
$
|
17,197
|
|
|
$
|
(119,907
|
)
|
|
$
|
334,598
|
|
|
$
|
(45,473
|
)
|
|
|
|
|
|
|
|
|
||||||||
Basic weighted-average common shares outstanding
|
111,701
|
|
|
111,277
|
|
|
111,698
|
|
|
111,274
|
|
||||
Dilutive effect of non-vested RSUs and contingent PSUs
|
1,929
|
|
|
—
|
|
|
1,569
|
|
|
—
|
|
||||
Dilutive effect of Senior Convertible Notes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Diluted weighted-average common shares outstanding
|
113,630
|
|
|
111,277
|
|
|
113,267
|
|
|
111,274
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Basic net income (loss) per common share
|
$
|
0.15
|
|
|
$
|
(1.08
|
)
|
|
$
|
3.00
|
|
|
$
|
(0.41
|
)
|
Diluted net income (loss) per common share
|
$
|
0.15
|
|
|
$
|
(1.08
|
)
|
|
$
|
2.95
|
|
|
$
|
(0.41
|
)
|
Contract Period
|
|
NYMEX WTI Volumes
|
|
Weighted-Average
Contract Price
|
|||
|
|
(MBbl)
|
|
(per Bbl)
|
|||
Third quarter 2018
|
|
1,769
|
|
|
$
|
49.77
|
|
Fourth quarter 2018
|
|
1,894
|
|
|
$
|
49.87
|
|
2019
|
|
1,940
|
|
|
$
|
50.70
|
|
Total
|
|
5,603
|
|
|
|
Contract Period
|
|
NYMEX WTI
Volumes
|
|
Weighted-
Average Floor
Price
|
|
Weighted-
Average Ceiling
Price
|
|||||
|
|
(MBbl)
|
|
(per Bbl)
|
|
(per Bbl)
|
|||||
Third quarter 2018
|
|
1,948
|
|
|
$
|
50.00
|
|
|
$
|
58.61
|
|
Fourth quarter 2018
|
|
2,222
|
|
|
$
|
50.00
|
|
|
$
|
58.44
|
|
2019
|
|
10,055
|
|
|
$
|
50.59
|
|
|
$
|
63.62
|
|
2020
|
|
366
|
|
|
$
|
55.00
|
|
|
$
|
67.01
|
|
Total
|
|
14,591
|
|
|
|
|
|
Contract Period
|
|
WTI Midland-NYMEX WTI Volumes
|
|
Weighted-Average
Contract Price
(1)
|
|
NYMEX WTI-ICE Brent Volumes
|
|
Weighted-Average
Contract Price (2) |
||||||
|
|
(MBbl)
|
|
(per Bbl)
|
|
(MBbl)
|
|
(per Bbl)
|
||||||
Third quarter 2018
|
|
3,018
|
|
|
$
|
(1.06
|
)
|
|
—
|
|
|
$
|
—
|
|
Fourth quarter 2018
|
|
3,327
|
|
|
$
|
(1.08
|
)
|
|
—
|
|
|
$
|
—
|
|
2019
|
|
11,217
|
|
|
$
|
(3.36
|
)
|
|
—
|
|
|
$
|
—
|
|
2020
|
|
7,250
|
|
|
$
|
(1.13
|
)
|
|
1,288
|
|
|
$
|
(7.97
|
)
|
2021
|
|
—
|
|
|
$
|
—
|
|
|
1,460
|
|
|
$
|
(7.80
|
)
|
2022
|
|
—
|
|
|
$
|
—
|
|
|
274
|
|
|
$
|
(7.67
|
)
|
Total
|
|
24,812
|
|
|
|
|
3,022
|
|
|
|
(1)
|
Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
|
(2)
|
Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).
|
Contract Period
|
|
Sold IF HSC
Volumes
|
|
Weighted-Average
Contract Price
|
|
Purchased IF HSC Volumes
|
|
Weighted-Average Contract Price
|
|
Net IF HSC
Volumes
|
|
Weighted-Average Contract Price
|
|||||||||
|
|
(BBtu)
|
|
(per MMBtu)
|
|
(BBtu)
|
|
(per MMBtu)
|
|
(BBtu)
|
|
(per MMBtu)
|
|||||||||
Third quarter 2018
|
|
28,218
|
|
|
$
|
3.25
|
|
|
(7,480
|
)
|
|
$
|
4.23
|
|
|
20,738
|
|
|
$
|
2.90
|
|
Fourth quarter 2018
|
|
28,204
|
|
|
$
|
3.27
|
|
|
(7,210
|
)
|
|
$
|
4.27
|
|
|
20,994
|
|
|
$
|
2.92
|
|
2019
|
|
41,394
|
|
|
$
|
3.87
|
|
|
(24,415
|
)
|
|
$
|
4.34
|
|
|
16,979
|
|
|
$
|
2.92
|
|
Total
|
|
97,816
|
|
|
|
|
(39,105
|
)
|
|
|
|
58,711
|
|
|
|
Contract Period
|
|
IF HSC
Volumes
|
|
Weighted-
Average Floor
Price
|
|
Weighted-
Average Ceiling
Price
|
|||||
|
|
(BBtu)
|
|
(per MMBtu)
|
|
(per MMBtu)
|
|||||
2019
|
|
14,242
|
|
|
$
|
2.50
|
|
|
$
|
2.83
|
|
Total
|
|
14,242
|
|
|
|
|
|
•
|
NYMEX WTI costless collar contracts for 2020 for a total of
0.8
MMBbl of oil production with contract floor prices of
$55.00
per Bbl and contract ceiling prices ranging from
$64.50
per Bbl to
$67.67
per Bbl;
|
•
|
fixed price NYMEX WTI-ICE Brent basis swap contracts for 2020 for a total of
0.6
MMBbl of oil production at contract prices ranging from
($8.06)
per Bbl to
($8.15)
per Bbl;
|
•
|
fixed price NYMEX WTI-ICE Brent basis swap contracts for 2021 for a total of
1.8
MMBbl of oil production at contract prices ranging from
($7.75)
per Bbl to
($8.00)
per Bbl;
|
•
|
fixed price NYMEX WTI-ICE Brent basis swap contracts for 2022 for a total of
2.6
MMBbl of oil production at contract prices ranging from
($7.60)
per Bbl to
($7.90)
per Bbl; and
|
•
|
fixed price OPIS Propane Mont Belvieu Non-TET swap contracts for 2019 for a total of
0.5
MMBbl of NGL production at contract prices ranging from
$32.21
per Bbl to
$32.26
per Bbl.
|
|
As of June 30,
2018
|
|
As of December 31, 2017
|
||||
|
(in thousands)
|
||||||
Derivative assets:
|
|
|
|
||||
Current assets
|
$
|
146,329
|
|
|
$
|
64,266
|
|
Noncurrent assets
|
31,151
|
|
|
40,362
|
|
||
Total derivative assets
|
$
|
177,480
|
|
|
$
|
104,628
|
|
Derivative liabilities:
|
|
|
|
||||
Current liabilities
|
$
|
259,338
|
|
|
$
|
172,582
|
|
Noncurrent liabilities
|
67,583
|
|
|
71,402
|
|
||
Total derivative liabilities
|
$
|
326,921
|
|
|
$
|
243,984
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||
|
As of
|
|
As of
|
||||||||||||
|
June 30,
2018 |
|
December 31, 2017
|
|
June 30,
2018 |
|
December 31, 2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Gross amounts presented in the accompanying balance sheets
|
$
|
177,480
|
|
|
$
|
104,628
|
|
|
$
|
(326,921
|
)
|
|
$
|
(243,984
|
)
|
Amounts not offset in the accompanying balance sheets
|
(147,009
|
)
|
|
(100,035
|
)
|
|
147,009
|
|
|
100,035
|
|
||||
Net amounts
|
$
|
30,471
|
|
|
$
|
4,593
|
|
|
$
|
(179,912
|
)
|
|
$
|
(143,949
|
)
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Derivative settlement (gain) loss:
|
|
|
|
|
|
|
|
||||||||
Oil contracts
|
$
|
24,430
|
|
|
$
|
2,754
|
|
|
$
|
45,178
|
|
|
$
|
11,838
|
|
Gas contracts
|
757
|
|
|
(21,751
|
)
|
|
(5,653
|
)
|
|
(39,257
|
)
|
||||
NGL contracts
|
11,478
|
|
|
2,694
|
|
|
21,668
|
|
|
11,109
|
|
||||
Total derivative settlement (gain) loss
|
$
|
36,665
|
|
|
$
|
(16,303
|
)
|
|
$
|
61,193
|
|
|
$
|
(16,310
|
)
|
|
|
|
|
|
|
|
|
||||||||
Net derivative (gain) loss:
|
|
|
|
|
|
|
|
||||||||
Oil contracts
|
$
|
22,402
|
|
|
$
|
(38,194
|
)
|
|
$
|
36,368
|
|
|
$
|
(87,784
|
)
|
Gas contracts
|
7,000
|
|
|
(6,038
|
)
|
|
16,990
|
|
|
(50,506
|
)
|
||||
NGL contracts
|
34,347
|
|
|
(10,957
|
)
|
|
17,920
|
|
|
(31,673
|
)
|
||||
Total net derivative (gain) loss
|
$
|
63,749
|
|
|
$
|
(55,189
|
)
|
|
$
|
71,278
|
|
|
$
|
(169,963
|
)
|
•
|
Level 1 – quoted prices in active markets for identical assets or liabilities
|
•
|
Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
|
•
|
Level 3 – significant inputs to the valuation model are unobservable
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
177,480
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
326,921
|
|
|
$
|
—
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
104,628
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
243,984
|
|
|
$
|
—
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
|
As of June 30, 2018
|
|
As of December 31, 2017
|
||||||||||||
|
Principal Amount
|
|
Fair Value
|
|
Principal Amount
|
|
Fair Value
|
||||||||
|
(in thousands)
|
||||||||||||||
6.50% Senior Notes due 2021
|
$
|
344,611
|
|
|
$
|
352,634
|
|
|
$
|
344,611
|
|
|
$
|
351,682
|
|
6.125% Senior Notes due 2022
|
$
|
561,796
|
|
|
$
|
573,847
|
|
|
$
|
561,796
|
|
|
$
|
571,627
|
|
6.50% Senior Notes due 2023
|
$
|
394,985
|
|
|
$
|
401,380
|
|
|
$
|
394,985
|
|
|
$
|
403,434
|
|
5.0% Senior Notes due 2024
|
$
|
500,000
|
|
|
$
|
468,750
|
|
|
$
|
500,000
|
|
|
$
|
483,440
|
|
5.625% Senior Notes due 2025
|
$
|
500,000
|
|
|
$
|
485,000
|
|
|
$
|
500,000
|
|
|
$
|
494,355
|
|
6.75% Senior Notes due 2026
|
$
|
500,000
|
|
|
$
|
502,350
|
|
|
$
|
500,000
|
|
|
$
|
516,350
|
|
1.50% Senior Convertible Notes due 2021
|
$
|
172,500
|
|
|
$
|
178,446
|
|
|
$
|
172,500
|
|
|
$
|
168,291
|
|
•
|
continue generating high margin returns from top tier projects that drive cash flow growth;
|
•
|
core up our portfolio to focus on assets that generate the highest returns; and
|
•
|
improve our credit metrics and maintain strong financial flexibility.
|
•
|
We recorded net income of
$17.2 million
and
$334.6 million
, or
$0.15
and
$2.95
per diluted share, for the three and six months ended
June 30, 2018
, respectively, compared with net loss of
$119.9 million
and
$45.5 million
, or
$1.08
and
$0.41
per diluted share, for the three and six months ended June 30,
2017
, respectively. Net income for the three and six months ended
June 30, 2018
, was driven largely by increased production revenue and net gain on divestiture activity of
$39.5 million
and
$424.9 million
, respectively, but was partially offset by net derivative losses of
$63.7 million
and
$71.3 million
for the three and six months ended
June 30, 2018
, respectively. Please refer to
Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2018, and 2017
below for additional discussion regarding the components of net income (loss) for each period presented.
|
•
|
We had net cash provided by operating activities of
$171.4 million
and
$311.5 million
for the three and six months ended
June 30, 2018
, respectively, compared with
$107.1 million
and
$242.1 million
for the same periods in
2017
, respectively. The increases in net cash provided by operating activities for the three and six months ended
June 30, 2018
, were driven largely by increased production revenue. Please refer to
Overview of Liquidity and Capital Resources
below for additional discussion of our sources and uses of cash.
|
•
|
Adjusted EBITDAX, a non-GAAP financial measure, for the three and six months ended
June 30, 2018
, was
$225.0 million
and
$435.1 million
, respectively, compared with
$154.0 million
and
$326.0 million
for the same periods in
2017
, respectively. The increases in adjusted EBITDAX for the three and six months ended
June 30, 2018
, were driven largely by increased production revenue and lower operating costs. Please refer to
Non-GAAP Financial Measures
below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our net income (loss) and net cash provided by operating activities to adjusted EBITDAX.
|
|
Midland Basin
|
|
Eagle Ford Shale
|
|
Bakken/Three Forks
(2)
|
|
Total
|
||||||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||
Wells drilled but not completed at December 31, 2017
|
49
|
|
|
41
|
|
|
33
|
|
|
30
|
|
|
18
|
|
|
15
|
|
|
100
|
|
|
86
|
|
Wells drilled
|
35
|
|
|
33
|
|
|
11
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|
41
|
|
Wells completed
|
(22
|
)
|
|
(17
|
)
|
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
|
(22
|
)
|
Other
(1)
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Wells drilled but not completed at March 31, 2018
|
62
|
|
|
58
|
|
|
39
|
|
|
33
|
|
|
18
|
|
|
15
|
|
|
119
|
|
|
106
|
|
Wells drilled
|
29
|
|
|
28
|
|
|
10
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
39
|
|
|
34
|
|
Wells completed
|
(41
|
)
|
|
(38
|
)
|
|
(16
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
(57
|
)
|
|
(47
|
)
|
Wells sold
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
(15
|
)
|
|
(18
|
)
|
|
(15
|
)
|
Wells drilled but not completed at June 30, 2018
|
50
|
|
|
48
|
|
|
33
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
83
|
|
|
78
|
|
(1)
|
Reflects net working interest changes resulting from normal business operations.
|
(2)
|
During the second quarter of 2018, we successfully closed on the sale of our remaining Bakken/Three Forks assets in Divide County, North Dakota. As a result, we will no longer have any drilling or completion activity in the Rocky Mountain region after the second quarter of 2018.
|
|
Permian
|
|
South Texas & Gulf Coast
|
|
Rocky Mountain
(1)
|
|
Total
|
||||||||||||||||
|
Three Months Ended June 30,
|
|
Three Months Ended June 30,
|
|
Three Months Ended June 30,
|
|
Three Months Ended June 30,
|
||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (MMBbl)
|
3.7
|
|
|
1.7
|
|
|
0.3
|
|
|
0.4
|
|
|
0.3
|
|
|
0.9
|
|
|
4.4
|
|
|
2.9
|
|
Gas (Bcf)
|
6.2
|
|
|
3.4
|
|
|
18.8
|
|
|
29.6
|
|
|
0.3
|
|
|
1.1
|
|
|
25.3
|
|
|
34.0
|
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
1.9
|
|
|
2.7
|
|
|
—
|
|
|
—
|
|
|
1.9
|
|
|
2.8
|
|
Equivalent (MMBOE)
|
4.8
|
|
|
2.3
|
|
|
5.4
|
|
|
8.0
|
|
|
0.4
|
|
|
1.1
|
|
|
10.5
|
|
|
11.3
|
|
Avg. daily equivalents (MBOE/d)
|
52.4
|
|
|
24.9
|
|
|
58.9
|
|
|
88.0
|
|
|
3.9
|
|
|
11.7
|
|
|
115.2
|
|
|
124.6
|
|
Relative percentage
|
46
|
%
|
|
20
|
%
|
|
51
|
%
|
|
71
|
%
|
|
3
|
%
|
|
9
|
%
|
|
100
|
%
|
|
100
|
%
|
(1)
|
During the first quarter of 2018, we closed the PRB Divestiture, and during the second quarter of 2018, we closed the Divide County Divestiture. As a result of these divestitures, we will no longer have production volumes from the Rocky Mountain region after the second quarter of 2018.
|
|
Permian
|
|
South Texas & Gulf Coast
|
|
Rocky Mountain
(1)
|
|
Total
|
||||||||||||||||
|
Six Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (MMBbl)
|
7.0
|
|
|
3.3
|
|
|
0.7
|
|
|
1.3
|
|
|
0.9
|
|
|
1.8
|
|
|
8.6
|
|
|
6.4
|
|
Gas (Bcf)
|
11.8
|
|
|
6.2
|
|
|
37.5
|
|
|
59.6
|
|
|
1.2
|
|
|
2.1
|
|
|
50.5
|
|
|
67.9
|
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
3.5
|
|
|
5.6
|
|
|
—
|
|
|
0.1
|
|
|
3.6
|
|
|
5.7
|
|
Equivalent (MMBOE)
|
9.0
|
|
|
4.4
|
|
|
10.5
|
|
|
16.8
|
|
|
1.1
|
|
|
2.3
|
|
|
20.6
|
|
|
23.4
|
|
Avg. daily equivalents (MBOE/d)
|
49.9
|
|
|
24.2
|
|
|
57.9
|
|
|
92.7
|
|
|
6.2
|
|
|
12.5
|
|
|
113.9
|
|
|
129.5
|
|
Relative percentage
|
44
|
%
|
|
19
|
%
|
|
51
|
%
|
|
71
|
%
|
|
5
|
%
|
|
10
|
%
|
|
100
|
%
|
|
100
|
%
|
(1)
|
During the first quarter of 2018, we closed the PRB Divestiture, and during the second quarter of 2018, we closed the Divide County Divestiture. As a result of these divestitures, we will no longer have production volumes from the Rocky Mountain region after the second quarter of 2018.
|
|
For the Three Months Ended
|
||||||||||
|
June 30, 2018
|
|
March 31, 2018
|
|
June 30, 2017
|
||||||
Oil (per Bbl):
|
|
|
|
|
|
||||||
Average NYMEX contract monthly price
|
$
|
67.88
|
|
|
$
|
62.87
|
|
|
$
|
48.28
|
|
Realized price, before the effect of derivative settlements
|
$
|
61.02
|
|
|
$
|
61.25
|
|
|
$
|
44.30
|
|
Effect of oil derivative settlements
|
$
|
(5.60
|
)
|
|
$
|
(4.86
|
)
|
|
$
|
(0.94
|
)
|
Gas:
|
|
|
|
|
|
||||||
Average NYMEX monthly settle price (per MMBtu)
|
$
|
2.80
|
|
|
$
|
3.00
|
|
|
$
|
3.18
|
|
Realized price, before the effect of derivative settlements (per Mcf)
|
$
|
3.32
|
|
|
$
|
3.14
|
|
|
$
|
2.99
|
|
Effect of gas derivative settlements (per Mcf)
|
$
|
(0.03
|
)
|
|
$
|
0.25
|
|
|
$
|
0.64
|
|
NGLs (per Bbl):
|
|
|
|
|
|
||||||
Average OPIS price
(1)
|
$
|
33.10
|
|
|
$
|
30.87
|
|
|
$
|
24.11
|
|
Realized price, before the effect of derivative settlements
|
$
|
27.55
|
|
|
$
|
25.53
|
|
|
$
|
19.71
|
|
Effect of NGL derivative settlements
|
$
|
(6.04
|
)
|
|
$
|
(6.09
|
)
|
|
$
|
(0.98
|
)
|
(1)
|
Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of
37%
Ethane,
32%
Propane,
6%
Isobutane,
11%
Normal Butane, and
14%
Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
|
|
As of July 25, 2018
|
|
As of June 30, 2018
|
||||
NYMEX WTI oil (per Bbl)
|
$
|
66.91
|
|
|
$
|
69.58
|
|
NYMEX Henry Hub gas (per MMBtu)
|
$
|
2.78
|
|
|
$
|
2.91
|
|
OPIS NGLs (per Bbl)
|
$
|
33.25
|
|
|
$
|
33.30
|
|
|
For the Three Months Ended
|
||||||||||||||
|
June 30,
|
|
March 31,
|
|
December 31,
|
|
September 30,
|
||||||||
|
2018
|
|
2018
|
|
2017
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
Production (MMBOE)
|
10.5
|
|
|
10.1
|
|
|
10.4
|
|
|
10.7
|
|
||||
Oil, gas, and NGL production revenue
|
$
|
402.6
|
|
|
$
|
382.9
|
|
|
$
|
341.2
|
|
|
$
|
294.5
|
|
Oil, gas, and NGL production expense
|
$
|
117.4
|
|
|
$
|
120.9
|
|
|
$
|
122.8
|
|
|
$
|
122.7
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
151.8
|
|
|
$
|
130.5
|
|
|
$
|
131.4
|
|
|
$
|
134.6
|
|
Exploration
(1)
|
$
|
14.1
|
|
|
$
|
13.7
|
|
|
$
|
15.8
|
|
|
$
|
14.1
|
|
General and administrative
(1)
|
$
|
28.9
|
|
|
$
|
27.7
|
|
|
$
|
32.7
|
|
|
$
|
27.6
|
|
Net income (loss)
|
$
|
17.2
|
|
|
$
|
317.4
|
|
|
$
|
(26.3
|
)
|
|
$
|
(89.1
|
)
|
(1)
|
Certain prior period amounts have been adjusted to conform to the current period presentation on the condensed consolidated financial statements. Please refer to
Recently Issued Accounting Standards
in
Note 1 - Summary of Significant Accounting Policies
in Part I, Item 1 of this report for additional discussion.
|
|
For the Three Months Ended
|
||||||||||||||
|
June 30,
|
|
March 31,
|
|
December 31,
|
|
September 30,
|
||||||||
|
2018
|
|
2018
|
|
2017
|
|
2017
|
||||||||
Average net daily production equivalent (MBOE per day)
|
115.2
|
|
|
112.7
|
|
|
112.6
|
|
|
116.0
|
|
||||
Lease operating expense (per BOE)
|
$
|
4.66
|
|
|
$
|
4.95
|
|
|
$
|
5.10
|
|
|
$
|
4.81
|
|
Transportation costs (per BOE)
|
$
|
4.47
|
|
|
$
|
4.63
|
|
|
$
|
5.01
|
|
|
$
|
5.24
|
|
Production taxes as a percent of oil, gas, and NGL production revenue
|
4.3
|
%
|
|
4.4
|
%
|
|
4.3
|
%
|
|
4.2
|
%
|
||||
Ad valorem tax expense (per BOE)
|
$
|
0.41
|
|
|
$
|
0.67
|
|
|
$
|
0.33
|
|
|
$
|
0.29
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
|
$
|
14.48
|
|
|
$
|
12.87
|
|
|
$
|
12.69
|
|
|
$
|
12.61
|
|
General and administrative (per BOE)
(1)
|
$
|
2.76
|
|
|
$
|
2.73
|
|
|
$
|
3.15
|
|
|
$
|
2.58
|
|
(1)
|
Certain prior period amounts have been adjusted to conform to the current period presentation on the condensed consolidated financial statements. Please refer to
Recently Issued Accounting Standards
in
Note 1 - Summary of Significant Accounting Policies
in Part I, Item 1 of this report for additional discussion.
|
|
For the Three Months Ended June 30,
|
|
Amount Change Between Periods
|
|
Percent Change Between Periods
|
|
For the Six Months Ended June 30,
|
|
Amount Change Between Periods
|
|
Percent Change Between Periods
|
||||||||||||||||||
|
2018
|
|
2017
|
|
|
2018
|
|
2017
|
|
||||||||||||||||||||
Net production volumes:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MMBbl)
|
4.4
|
|
|
2.9
|
|
|
1.5
|
|
|
50
|
%
|
|
8.6
|
|
|
6.4
|
|
|
2.2
|
|
|
34
|
%
|
||||||
Gas (Bcf)
|
25.3
|
|
|
34.0
|
|
|
(8.7
|
)
|
|
(26
|
)%
|
|
50.5
|
|
|
67.9
|
|
|
(17.4
|
)
|
|
(26
|
)%
|
||||||
NGLs (MMBbl)
|
1.9
|
|
|
2.8
|
|
|
(0.9
|
)
|
|
(31
|
)%
|
|
3.6
|
|
|
5.7
|
|
|
(2.1
|
)
|
|
(37
|
)%
|
||||||
Equivalent (MMBOE)
|
10.5
|
|
|
11.3
|
|
|
(0.9
|
)
|
|
(8
|
)%
|
|
20.6
|
|
|
23.4
|
|
|
(2.8
|
)
|
|
(12
|
)%
|
||||||
Average net daily production:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MBbl per day)
|
47.9
|
|
|
32.0
|
|
|
16.0
|
|
|
50
|
%
|
|
47.6
|
|
|
35.5
|
|
|
12.1
|
|
|
34
|
%
|
||||||
Gas (MMcf per day)
|
278.3
|
|
|
374.1
|
|
|
(95.8
|
)
|
|
(26
|
)%
|
|
279.3
|
|
|
375.3
|
|
|
(96.1
|
)
|
|
(26
|
)%
|
||||||
NGLs (MBbl per day)
|
20.9
|
|
|
30.3
|
|
|
(9.4
|
)
|
|
(31
|
)%
|
|
19.7
|
|
|
31.4
|
|
|
(11.6
|
)
|
|
(37
|
)%
|
||||||
Equivalent (MBOE per day)
|
115.2
|
|
|
124.6
|
|
|
(9.4
|
)
|
|
(8
|
)%
|
|
113.9
|
|
|
129.5
|
|
|
(15.5
|
)
|
|
(12
|
)%
|
||||||
Oil, gas, and NGL production revenue (in millions):
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil production revenue
|
$
|
266.2
|
|
|
$
|
128.9
|
|
|
$
|
137.3
|
|
|
107
|
%
|
|
$
|
527.2
|
|
|
$
|
296.5
|
|
|
$
|
230.7
|
|
|
78
|
%
|
Gas production revenue
|
84.1
|
|
|
101.7
|
|
|
(17.6
|
)
|
|
(17
|
)%
|
|
163.2
|
|
|
202.9
|
|
|
(39.7
|
)
|
|
(20
|
)%
|
||||||
NGL production revenue
|
52.3
|
|
|
54.3
|
|
|
(2.0
|
)
|
|
(4
|
)%
|
|
95.1
|
|
|
118.7
|
|
|
(23.7
|
)
|
|
(20
|
)%
|
||||||
Total oil, gas, and NGL production revenue
|
$
|
402.6
|
|
|
$
|
284.9
|
|
|
$
|
117.6
|
|
|
41
|
%
|
|
$
|
785.4
|
|
|
$
|
618.1
|
|
|
$
|
167.3
|
|
|
27
|
%
|
Oil, gas, and NGL production expense (in millions):
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expense
|
$
|
48.8
|
|
|
$
|
46.6
|
|
|
$
|
2.2
|
|
|
5
|
%
|
|
$
|
99.0
|
|
|
$
|
92.7
|
|
|
$
|
6.3
|
|
|
7
|
%
|
Transportation costs
|
46.9
|
|
|
64.7
|
|
|
(17.8
|
)
|
|
(28
|
)%
|
|
93.8
|
|
|
135.8
|
|
|
(42.0
|
)
|
|
(31
|
)%
|
||||||
Production taxes
|
17.4
|
|
|
11.3
|
|
|
6.1
|
|
|
54
|
%
|
|
34.4
|
|
|
25.4
|
|
|
9.0
|
|
|
35
|
%
|
||||||
Ad valorem tax expense
|
4.3
|
|
|
1.8
|
|
|
2.5
|
|
|
139
|
%
|
|
11.1
|
|
|
8.5
|
|
|
2.6
|
|
|
31
|
%
|
||||||
Total oil, gas, and NGL production expense
|
$
|
117.4
|
|
|
$
|
124.4
|
|
|
$
|
(7.0
|
)
|
|
(6
|
)%
|
|
$
|
238.3
|
|
|
$
|
262.4
|
|
|
$
|
(24.1
|
)
|
|
(9
|
)%
|
Realized price (before the effect of derivative settlements):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (per Bbl)
|
$
|
61.02
|
|
|
$
|
44.30
|
|
|
$
|
16.72
|
|
|
38
|
%
|
|
$
|
61.14
|
|
|
$
|
46.08
|
|
|
$
|
15.06
|
|
|
33
|
%
|
Gas (per Mcf)
|
$
|
3.32
|
|
|
$
|
2.99
|
|
|
$
|
0.33
|
|
|
11
|
%
|
|
$
|
3.23
|
|
|
$
|
2.99
|
|
|
$
|
0.24
|
|
|
8
|
%
|
NGLs (per Bbl)
|
$
|
27.55
|
|
|
$
|
19.71
|
|
|
$
|
7.84
|
|
|
40
|
%
|
|
$
|
26.60
|
|
|
$
|
20.92
|
|
|
$
|
5.68
|
|
|
27
|
%
|
Per BOE
|
$
|
38.40
|
|
|
$
|
25.13
|
|
|
$
|
13.27
|
|
|
53
|
%
|
|
$
|
38.09
|
|
|
$
|
26.38
|
|
|
$
|
11.71
|
|
|
44
|
%
|
Per BOE data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expense
|
$
|
4.66
|
|
|
$
|
4.11
|
|
|
$
|
0.55
|
|
|
13
|
%
|
|
$
|
4.80
|
|
|
$
|
3.96
|
|
|
$
|
0.84
|
|
|
21
|
%
|
Transportation costs
|
$
|
4.47
|
|
|
$
|
5.71
|
|
|
$
|
(1.24
|
)
|
|
(22
|
)%
|
|
$
|
4.55
|
|
|
$
|
5.79
|
|
|
$
|
(1.24
|
)
|
|
(21
|
)%
|
Production taxes
|
$
|
1.66
|
|
|
$
|
1.00
|
|
|
$
|
0.66
|
|
|
66
|
%
|
|
$
|
1.67
|
|
|
$
|
1.09
|
|
|
$
|
0.58
|
|
|
53
|
%
|
Ad valorem tax expense
|
$
|
0.41
|
|
|
$
|
0.16
|
|
|
$
|
0.25
|
|
|
156
|
%
|
|
$
|
0.54
|
|
|
$
|
0.36
|
|
|
$
|
0.18
|
|
|
50
|
%
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
14.48
|
|
|
$
|
13.52
|
|
|
$
|
0.96
|
|
|
7
|
%
|
|
$
|
13.69
|
|
|
$
|
12.42
|
|
|
$
|
1.27
|
|
|
10
|
%
|
General and administrative
(2)
|
$
|
2.76
|
|
|
$
|
2.49
|
|
|
$
|
0.27
|
|
|
11
|
%
|
|
$
|
2.74
|
|
|
$
|
2.43
|
|
|
$
|
0.31
|
|
|
13
|
%
|
Derivative settlement gain (loss)
(3)
|
$
|
(3.49
|
)
|
|
$
|
1.44
|
|
|
$
|
(4.93
|
)
|
|
(342
|
)%
|
|
$
|
(2.97
|
)
|
|
$
|
0.70
|
|
|
$
|
(3.67
|
)
|
|
(524
|
)%
|
Earnings per share information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Basic net income (loss) per common share
|
$
|
0.15
|
|
|
$
|
(1.08
|
)
|
|
$
|
1.23
|
|
|
114
|
%
|
|
$
|
3.00
|
|
|
$
|
(0.41
|
)
|
|
$
|
3.41
|
|
|
832
|
%
|
Diluted net income (loss) per common share
|
$
|
0.15
|
|
|
$
|
(1.08
|
)
|
|
$
|
1.23
|
|
|
114
|
%
|
|
$
|
2.95
|
|
|
$
|
(0.41
|
)
|
|
$
|
3.36
|
|
|
820
|
%
|
Basic weighted-average common shares outstanding (in thousands)
|
111,701
|
|
|
111,277
|
|
|
424
|
|
|
—
|
%
|
|
111,698
|
|
|
111,274
|
|
|
424
|
|
|
—
|
%
|
||||||
Diluted weighted-average common shares outstanding (in thousands)
|
113,630
|
|
|
111,277
|
|
|
2,353
|
|
|
2
|
%
|
|
113,267
|
|
|
111,274
|
|
|
1,993
|
|
|
2
|
%
|
(1)
|
Amount and percentage changes may not calculate due to rounding.
|
(2)
|
Prior periods have been adjusted to conform to the current period presentation on the condensed consolidated financial statements. Please refer to
Recently Issued Accounting Standards
in
Note 1 - Summary of Significant Accounting Policies
in Part I, Item 1 of this report for additional discussion.
|
(3)
|
Derivative settlements for the three and
six
months ended
June 30, 2018
, and
2017
, are included within the net derivative (gain) loss line item in the accompanying statements of operations.
|
|
Net Equivalent Production
Increase (Decrease)
|
|
Production Revenue
Increase (Decrease)
|
|
Production Expense
Increase (Decrease)
|
||||||||||||||||
|
Three Months Ended
|
|
Six Months Ended
|
|
Three Months Ended
|
|
Six Months Ended
|
|
Three Months Ended
|
|
Six Months Ended
|
||||||||||
|
(MMBOE)
|
|
(in millions)
|
|
(in millions)
|
||||||||||||||||
Permian
|
2.5
|
|
|
4.7
|
|
|
$
|
167.9
|
|
|
$
|
305.7
|
|
|
$
|
20.6
|
|
|
$
|
41.6
|
|
South Texas & Gulf Coast
|
(2.6
|
)
|
|
(6.3
|
)
|
|
(30.6
|
)
|
|
(106.9
|
)
|
|
(17.5
|
)
|
|
(52.4
|
)
|
||||
Rocky Mountain
(1)
|
(0.7
|
)
|
|
(1.2
|
)
|
|
(19.7
|
)
|
|
(31.5
|
)
|
|
(10.1
|
)
|
|
(13.4
|
)
|
||||
Total
|
(0.9
|
)
|
|
(2.8
|
)
|
|
$
|
117.6
|
|
|
$
|
167.3
|
|
|
$
|
(7.0
|
)
|
|
$
|
(24.1
|
)
|
(1)
|
During the first quarter of 2018, we closed the PRB Divestiture, and during the second quarter of 2018, we closed the Divide County Divestiture. As a result of these divestitures, we will no longer have production volumes from the Rocky Mountain region after the second quarter of 2018.
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
151.8
|
|
|
$
|
153.2
|
|
|
$
|
282.2
|
|
|
$
|
291.0
|
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
Exploration
(1)
|
$
|
14.1
|
|
|
$
|
13.0
|
|
|
$
|
27.8
|
|
|
$
|
24.8
|
|
(1)
|
Prior periods have been adjusted to conform to the current period presentation on the condensed consolidated financial statements. Please refer to
Recently Issued Accounting Standards
in
Note 1 - Summary of Significant Accounting Policies
in Part I, Item 1 of this report for additional discussion.
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
Abandonment and impairment of unproved properties
|
$
|
11.9
|
|
|
$
|
0.2
|
|
|
$
|
17.6
|
|
|
$
|
0.2
|
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
General and administrative
(1)
|
$
|
28.9
|
|
|
$
|
28.2
|
|
|
$
|
56.6
|
|
|
$
|
57.1
|
|
(1)
|
Prior periods have been adjusted to conform to the current period presentation on the condensed consolidated financial statements. Please refer to
Recently Issued Accounting Standards
in
Note 1 - Summary of Significant Accounting Policies
in Part I, Item 1 of this report for additional discussion.
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions, except tax rate)
|
||||||||||||||
Income tax (expense) benefit
|
$
|
0.9
|
|
|
$
|
71.1
|
|
|
$
|
(98.1
|
)
|
|
$
|
26.6
|
|
Effective tax rate
|
(5.5
|
)%
|
|
37.2
|
%
|
|
22.7
|
%
|
|
36.9
|
%
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
Weighted-average interest rate
|
6.4
|
%
|
|
6.4
|
%
|
|
6.5
|
%
|
|
6.5
|
%
|
Weighted-average borrowing rate
|
5.8
|
%
|
|
5.8
|
%
|
|
5.8
|
%
|
|
5.8
|
%
|
|
For the Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Net cash provided by operating activities
|
$
|
311.5
|
|
|
$
|
242.1
|
|
|
For the Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Net cash provided by (used in) investing activities
|
$
|
(5.7
|
)
|
|
$
|
311.4
|
|
|
For the Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Net cash used in financing activities
|
$
|
(3.8
|
)
|
|
$
|
(6.3
|
)
|
|
For the Three Months Ended
June 30, |
|
For the Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Net income (loss) (GAAP)
|
$
|
17,197
|
|
|
$
|
(119,907
|
)
|
|
$
|
334,598
|
|
|
$
|
(45,473
|
)
|
Interest expense
|
41,654
|
|
|
44,595
|
|
|
84,739
|
|
|
91,548
|
|
||||
Interest income
(1)
|
(2,414
|
)
|
|
(1,265
|
)
|
|
(3,263
|
)
|
|
(1,600
|
)
|
||||
Income tax expense (benefit)
|
(901
|
)
|
|
(71,061
|
)
|
|
98,090
|
|
|
(26,555
|
)
|
||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
151,765
|
|
|
153,232
|
|
|
282,238
|
|
|
291,044
|
|
||||
Exploration
(2) (3)
|
12,867
|
|
|
11,988
|
|
|
25,278
|
|
|
22,397
|
|
||||
Abandonment and impairment of unproved properties
|
11,935
|
|
|
157
|
|
|
17,560
|
|
|
157
|
|
||||
Stock-based compensation expense
|
5,264
|
|
|
4,358
|
|
|
10,676
|
|
|
9,813
|
|
||||
Net derivative (gain) loss
|
63,749
|
|
|
(55,189
|
)
|
|
71,278
|
|
|
(169,963
|
)
|
||||
Derivative settlement gain (loss)
|
(36,665
|
)
|
|
16,303
|
|
|
(61,193
|
)
|
|
16,310
|
|
||||
Net (gain) loss on divestiture activity
|
(39,501
|
)
|
|
167,133
|
|
|
(424,870
|
)
|
|
129,670
|
|
||||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
35
|
|
||||
Other, net
|
2
|
|
|
3,655
|
|
|
9
|
|
|
8,641
|
|
||||
Adjusted EBITDAX (non-GAAP)
(3)
|
224,952
|
|
|
153,999
|
|
|
435,140
|
|
|
326,024
|
|
||||
Interest expense
|
(41,654
|
)
|
|
(44,595
|
)
|
|
(84,739
|
)
|
|
(91,548
|
)
|
||||
Interest income
(1)
|
2,414
|
|
|
1,265
|
|
|
3,263
|
|
|
1,600
|
|
||||
Income tax (expense) benefit
|
901
|
|
|
71,061
|
|
|
(98,090
|
)
|
|
26,555
|
|
||||
Exploration
(2) (3)
|
(12,867
|
)
|
|
(11,988
|
)
|
|
(25,278
|
)
|
|
(22,397
|
)
|
||||
Amortization of debt discount and deferred financing costs
|
3,884
|
|
|
3,733
|
|
|
7,750
|
|
|
8,679
|
|
||||
Deferred income taxes
|
(861
|
)
|
|
(64,015
|
)
|
|
97,505
|
|
|
(30,790
|
)
|
||||
Other, net
(3)
|
223
|
|
|
(2,567
|
)
|
|
(2,311
|
)
|
|
(4,177
|
)
|
||||
Net change in working capital
|
(5,609
|
)
|
|
256
|
|
|
(21,722
|
)
|
|
28,182
|
|
||||
Net cash provided by operating activities (GAAP)
(3)
|
$
|
171,383
|
|
|
$
|
107,149
|
|
|
$
|
311,518
|
|
|
$
|
242,128
|
|
(1)
|
Interest income is included within the other non-operating income, net line item on the accompanying statements of operations in Part I, Item 1 of this report.
|
(2)
|
Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.
|
(3)
|
Certain prior period amounts have been adjusted to conform to the current period presentation on the condensed consolidated financial statements. Please refer to
Note 1 - Summary of Significant Accounting Policies
in Part I, Item 1 of this report for additional discussion.
|
•
|
the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
|
•
|
our outlook on future oil, gas, and NGL prices, well costs, and service costs;
|
•
|
the drilling of wells and other exploration and development activities and plans, as well as possible or expected acquisitions or divestitures;
|
•
|
proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;
|
•
|
future oil, gas, and NGL production estimates;
|
•
|
cash flows, anticipated liquidity, and the future repayment of debt;
|
•
|
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations;
|
•
|
the possible divestiture or farm-down of, or joint venture relating to, certain properties; and
|
•
|
other similar matters such as those discussed in the
Management’s Discussion and Analysis of Financial Condition and Results of Operations
section in Part I, Item 2 of this report.
|
•
|
the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;
|
•
|
weakness in economic conditions and uncertainty in financial markets;
|
•
|
our ability to replace reserves in order to sustain production;
|
•
|
our ability to raise the substantial amount of capital required to develop and/or replace our reserves;
|
•
|
our ability to compete against competitors that have greater financial, technical, and human resources;
|
•
|
our ability to attract and retain key personnel;
|
•
|
the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;
|
•
|
the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;
|
•
|
the possibility that exploration and development drilling may not result in commercially producible reserves;
|
•
|
our limited control over activities on outside-operated properties;
|
•
|
our reliance on the skill and expertise of third-party service providers on our operated properties;
|
•
|
the possibility that title to properties in which we claim an interest may be defective;
|
•
|
our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;
|
•
|
the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;
|
•
|
the uncertainties associated with enhanced recovery methods;
|
•
|
our commodity derivative contracts may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;
|
•
|
the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;
|
•
|
our ability to deliver required quantities of oil, gas, NGLs, or produced water to contractual counterparties;
|
•
|
price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
|
•
|
the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;
|
•
|
the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;
|
•
|
the possibility that covenants in our Credit Agreement or the indentures governing the Senior Notes and Senior Convertible Notes may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions, or lead to the accelerated payment of our debt;
|
•
|
operating and environmental risks and hazards that could result in substantial losses;
|
•
|
the impact of extreme weather conditions on our ability to conduct drilling activities;
|
•
|
our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;
|
•
|
complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;
|
•
|
the availability and capacity of gathering, transportation, processing, and/or refining facilities;
|
•
|
our ability to sell and/or receive market prices for our oil, gas, and NGLs;
|
•
|
new technologies may cause our current exploration and drilling methods to become obsolete;
|
•
|
the possibility of security threats, including terrorist attacks and cybersecurity attacks and breaches, against, or otherwise impacting, our facilities and systems; and
|
•
|
litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.
|
Period
|
Total Number of Shares Purchased
(1)
|
Weighted Average Price Paid per Share
|
Total Number of Shares Purchased as Part of Publicly Announced Program
|
Maximum Number of Shares that May Yet Be Purchased Under the Program
(2)
|
|||||
04/01/18 - 04/30/18
|
—
|
|
$
|
—
|
|
—
|
|
3,072,184
|
|
05/01/18 - 05/31/18
|
355
|
|
$
|
26.64
|
|
—
|
|
3,072,184
|
|
06/01/18 - 06/30/18
|
—
|
|
$
|
—
|
|
—
|
|
3,072,184
|
|
Total:
|
355
|
|
$
|
26.64
|
|
—
|
|
3,072,184
|
|
(1)
|
All shares purchased by us in the
second
quarter of 2018 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs delivered under the terms of grants under the Equity Incentive Compensation Plan.
|
(2)
|
In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time.
|
Exhibit Number
|
|
Description
|
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Schema Document
|
101.CAL*
|
|
XBRL Calculation Linkbase Document
|
101.LAB*
|
|
XBRL Label Linkbase Document
|
101.PRE*
|
|
XBRL Presentation Linkbase Document
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
*
|
|
Filed with this report.
|
|
**
|
|
Furnished with this report.
|
|
†
|
|
Exhibit constitutes a management contract or compensatory plan or agreement.
|
|
SM ENERGY COMPANY
|
||
|
|
|
|
August 2, 2018
|
By:
|
/s/ JAVAN D. OTTOSON
|
|
|
|
Javan D. Ottoson
|
|
|
|
President and Chief Executive Officer
|
|
|
|
(Principal Executive Officer)
|
|
|
|
|
|
August 2, 2018
|
By:
|
/s/ A. WADE PURSELL
|
|
|
|
A. Wade Pursell
|
|
|
|
Executive Vice President and Chief Financial Officer
|
|
|
|
(Principal Financial Officer)
|
|
|
|
|
|
August 2, 2018
|
By:
|
/s/ MARK T. SOLOMON
|
|
|
|
Mark T. Solomon
|
|
|
|
Vice President - Controller and Assistant Secretary
|
|
|
|
(Principal Accounting Officer)
|
|
Relative Performance Table
|
|
|
|
|||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
|
|
Peer Group Count
|
|
DACFG and TSR Multipliers
|
|||||||||||||||||||||||||
|
|
21
|
20
|
19
|
18
|
17
|
16
|
15
|
14
|
13
|
12
|
11
|
10
|
|
Peer Group Percentile
|
Multiplier
|
|||||||||||||
|
1
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
100.00
|
%
|
|
0%
|
0.0
|
|
2
|
95.00
|
%
|
94.80
|
%
|
94.50
|
%
|
94.20
|
%
|
93.80
|
%
|
93.40
|
%
|
92.90
|
%
|
92.40
|
%
|
91.70
|
%
|
91.00
|
%
|
90.00
|
%
|
88.90
|
%
|
|
5%
|
0.0
|
||
3
|
90.00
|
%
|
89.50
|
%
|
88.90
|
%
|
88.30
|
%
|
87.50
|
%
|
86.70
|
%
|
85.80
|
%
|
84.70
|
%
|
83.40
|
%
|
81.90
|
%
|
80.00
|
%
|
77.80
|
%
|
|
10%
|
0.0
|
||
4
|
85.00
|
%
|
84.30
|
%
|
83.40
|
%
|
82.40
|
%
|
81.30
|
%
|
80.00
|
%
|
78.60
|
%
|
77.00
|
%
|
75.00
|
%
|
72.80
|
%
|
70.00
|
%
|
66.70
|
%
|
|
15%
|
0.0
|
||
5
|
80.00
|
%
|
79.00
|
%
|
77.80
|
%
|
76.50
|
%
|
75.00
|
%
|
73.40
|
%
|
71.50
|
%
|
69.30
|
%
|
66.70
|
%
|
63.70
|
%
|
60.00
|
%
|
55.60
|
%
|
|
20%
|
0.0
|
||
6
|
75.00
|
%
|
73.70
|
%
|
72.30
|
%
|
70.60
|
%
|
68.80
|
%
|
66.70
|
%
|
64.30
|
%
|
61.60
|
%
|
58.40
|
%
|
54.60
|
%
|
50.00
|
%
|
44.50
|
%
|
|
25%
|
0.0
|
||
7
|
70.00
|
%
|
68.50
|
%
|
66.70
|
%
|
64.80
|
%
|
62.50
|
%
|
60.00
|
%
|
57.20
|
%
|
53.90
|
%
|
50.00
|
%
|
45.50
|
%
|
40.00
|
%
|
33.40
|
%
|
|
30%
|
0.5
|
||
8
|
65.00
|
%
|
63.20
|
%
|
61.20
|
%
|
58.90
|
%
|
56.30
|
%
|
53.40
|
%
|
50.00
|
%
|
46.20
|
%
|
41.70
|
%
|
36.40
|
%
|
30.00
|
%
|
22.30
|
%
|
|
35%
|
0.6
|
||
9
|
60.00
|
%
|
57.90
|
%
|
55.60
|
%
|
53.00
|
%
|
50.00
|
%
|
46.70
|
%
|
42.90
|
%
|
38.50
|
%
|
33.40
|
%
|
27.30
|
%
|
20.00
|
%
|
11.20
|
%
|
|
40%
|
0.7
|
||
10
|
55.00
|
%
|
52.70
|
%
|
50.00
|
%
|
47.10
|
%
|
43.80
|
%
|
40.00
|
%
|
35.80
|
%
|
30.80
|
%
|
25.00
|
%
|
18.20
|
%
|
10.00
|
%
|
0.00
|
%
|
|
45%
|
0.8
|
||
11
|
50.00
|
%
|
47.40
|
%
|
44.50
|
%
|
41.20
|
%
|
37.50
|
%
|
33.40
|
%
|
28.60
|
%
|
23.10
|
%
|
16.70
|
%
|
9.10
|
%
|
0.00
|
%
|
NA
|
|
|
50%
|
0.9
|
||
12
|
45.00
|
%
|
42.20
|
%
|
38.90
|
%
|
35.30
|
%
|
31.30
|
%
|
26.70
|
%
|
21.50
|
%
|
15.40
|
%
|
8.40
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
|
55%
|
1.0
|
||
13
|
40.00
|
%
|
36.90
|
%
|
33.40
|
%
|
29.50
|
%
|
25.00
|
%
|
20.00
|
%
|
14.30
|
%
|
7.70
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
|
60%
|
1.2
|
||
14
|
35.00
|
%
|
31.60
|
%
|
27.80
|
%
|
23.60
|
%
|
18.80
|
%
|
13.40
|
%
|
7.20
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
|
65%
|
1.4
|
||
15
|
30.00
|
%
|
26.40
|
%
|
22.30
|
%
|
17.70
|
%
|
12.50
|
%
|
6.70
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
|
70%
|
1.6
|
||
16
|
25.00
|
%
|
21.10
|
%
|
16.70
|
%
|
11.80
|
%
|
6.30
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
|
75%
|
1.8
|
||
17
|
20.00
|
%
|
15.80
|
%
|
11.20
|
%
|
5.90
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
|
80%
|
2.0
|
||
18
|
15.00
|
%
|
10.60
|
%
|
5.60
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
|
85%
|
2.0
|
||
19
|
10.00
|
%
|
5.30
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
|
90%
|
2.0
|
||
20
|
5.00
|
%
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
|
95%
|
2.0
|
||
21
|
0.00
|
%
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
NA
|
|
|
100%
|
2.0
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
1
|
|
Peer group count excludes SM Energy
|
|
|
For the Six Months Ended June 30,
|
|
For the Years Ended December 31,
|
||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
|
(in thousands, except ratios)
|
||||||||||||||||||||||
Income (loss) before income taxes
|
$
|
432,688
|
|
|
$
|
(343,813
|
)
|
|
$
|
(1,201,916
|
)
|
|
$
|
(722,861
|
)
|
|
$
|
1,064,699
|
|
|
$
|
278,611
|
|
Fixed charges
|
96,078
|
|
|
193,587
|
|
|
167,600
|
|
|
155,510
|
|
|
117,147
|
|
|
102,758
|
|
||||||
Amortization of capitalized interest
|
5,017
|
|
|
11,623
|
|
|
13,905
|
|
|
9,116
|
|
|
11,448
|
|
|
11,784
|
|
||||||
Capitalized interest
|
(10,536
|
)
|
|
(12,607
|
)
|
|
(17,004
|
)
|
|
(25,051
|
)
|
|
(16,165
|
)
|
|
(10,952
|
)
|
||||||
Earnings before fixed charges
|
$
|
523,247
|
|
|
$
|
(151,210
|
)
|
|
$
|
(1,037,415
|
)
|
|
$
|
(583,286
|
)
|
|
$
|
1,177,129
|
|
|
$
|
382,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense
(1)
|
$
|
84,739
|
|
|
$
|
179,257
|
|
|
$
|
148,685
|
|
|
$
|
128,149
|
|
|
$
|
98,554
|
|
|
$
|
89,711
|
|
Capitalized interest
|
10,536
|
|
|
12,607
|
|
|
17,004
|
|
|
25,051
|
|
|
16,165
|
|
|
10,952
|
|
||||||
Interest expense component of rent
(2)
|
803
|
|
|
1,723
|
|
|
1,911
|
|
|
2,310
|
|
|
2,428
|
|
|
2,095
|
|
||||||
Total fixed charges
|
$
|
96,078
|
|
|
$
|
193,587
|
|
|
$
|
167,600
|
|
|
$
|
155,510
|
|
|
$
|
117,147
|
|
|
$
|
102,758
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Ratio of earnings to fixed charges
|
5.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10.0
|
|
|
3.7
|
|
||||||
Insufficient coverage
|
$
|
—
|
|
|
$
|
344,797
|
|
|
$
|
1,205,015
|
|
|
$
|
738,796
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Includes amortization of deferred financing costs and debt discount. Interest expense for the year ended December 31, 2016, excludes the $10.0 million paid to terminate a second lien facility that was no longer necessary to fund acquisition activity.
|
(2)
|
Represents a reasonable approximation of the portion of rental expense assumed to be attributable to the interest factor.
|
1.
|
I have reviewed this quarterly report on Form 10-Q of SM Energy Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
1.
|
I have reviewed this quarterly report on Form 10-Q of SM Energy Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
/s/ JAVAN D. OTTOSON
|
|
Javan D. Ottoson
|
|
President and Chief Executive Officer
|
|
August 2, 2018
|
|
|
|
|
|
/s/ A. WADE PURSELL
|
|
A. Wade Pursell
|
|
Executive Vice President and Chief Financial Officer
|
|
August 2, 2018
|
|