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Share Name | Share Symbol | Market | Type |
---|---|---|---|
SM Energy Company | NYSE:SM | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
2.39 | 5.01% | 50.13 | 50.2675 | 48.00 | 48.72 | 3,340,961 | 01:00:00 |
Delaware
(State or other jurisdiction
of incorporation or organization)
|
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41-0518430
(I.R.S. Employer
Identification No.)
|
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1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
|
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80203
(Zip Code)
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PAGE
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September 30,
2018 |
|
December 31,
2017 |
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
176,806
|
|
|
$
|
313,943
|
|
Accounts receivable
|
179,347
|
|
|
160,154
|
|
||
Derivative assets
|
81,163
|
|
|
64,266
|
|
||
Prepaid expenses and other
|
15,826
|
|
|
10,752
|
|
||
Total current assets
|
453,142
|
|
|
549,115
|
|
||
Property and equipment (successful efforts method):
|
|
|
|
||||
Proved oil and gas properties
|
6,686,922
|
|
|
6,139,379
|
|
||
Accumulated depletion, depreciation, and amortization
|
(3,240,124
|
)
|
|
(3,171,575
|
)
|
||
Unproved oil and gas properties
|
1,892,557
|
|
|
2,047,203
|
|
||
Wells in progress
|
328,808
|
|
|
321,347
|
|
||
Properties held for sale, net
|
5,040
|
|
|
111,700
|
|
||
Other property and equipment, net of accumulated depreciation of $56,067 and $49,985, respectively
|
102,984
|
|
|
106,738
|
|
||
Total property and equipment, net
|
5,776,187
|
|
|
5,554,792
|
|
||
Noncurrent assets:
|
|
|
|
||||
Derivative assets
|
8,853
|
|
|
40,362
|
|
||
Other noncurrent assets
|
35,539
|
|
|
32,507
|
|
||
Total noncurrent assets
|
44,392
|
|
|
72,869
|
|
||
Total assets
|
$
|
6,273,721
|
|
|
$
|
6,176,776
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses
|
$
|
429,698
|
|
|
$
|
386,630
|
|
Derivative liabilities
|
304,159
|
|
|
172,582
|
|
||
Total current liabilities
|
733,857
|
|
|
559,212
|
|
||
Noncurrent liabilities:
|
|
|
|
||||
Revolving credit facility
|
—
|
|
|
—
|
|
||
Senior Notes, net of unamortized deferred financing costs
|
2,447,290
|
|
|
2,769,663
|
|
||
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
145,662
|
|
|
139,107
|
|
||
Asset retirement obligations
|
88,149
|
|
|
103,026
|
|
||
Asset retirement obligations associated with oil and gas properties held for sale
|
—
|
|
|
11,369
|
|
||
Deferred income taxes
|
140,949
|
|
|
79,989
|
|
||
Derivative liabilities
|
72,605
|
|
|
71,402
|
|
||
Other noncurrent liabilities
|
45,810
|
|
|
48,400
|
|
||
Total noncurrent liabilities
|
2,940,465
|
|
|
3,222,956
|
|
||
|
|
|
|
||||
Commitments and contingencies (note 6)
|
|
|
|
|
|
||
|
|
|
|
||||
Stockholders’ equity:
|
|
|
|
||||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,137,582 and 111,687,016 shares, respectively
|
1,121
|
|
|
1,117
|
|
||
Additional paid-in capital
|
1,758,205
|
|
|
1,741,623
|
|
||
Retained earnings
(1)
|
856,111
|
|
|
665,657
|
|
||
Accumulated other comprehensive loss
(1)
|
(16,038
|
)
|
|
(13,789
|
)
|
||
Total stockholders
’
equity
|
2,599,399
|
|
|
2,394,608
|
|
||
Total liabilities and stockholders
’
equity
|
$
|
6,273,721
|
|
|
$
|
6,176,776
|
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
|
|
(as adjusted)
|
|
|
|
(as adjusted)
|
||||||||
Operating revenues and other income:
|
|
|
|
|
|
|
|
||||||||
Oil, gas, and NGL production revenue
|
$
|
458,382
|
|
|
$
|
294,459
|
|
|
$
|
1,243,826
|
|
|
$
|
912,596
|
|
Net gain (loss) on divestiture activity
|
786
|
|
|
(1,895
|
)
|
|
425,656
|
|
|
(131,565
|
)
|
||||
Other operating revenues
|
201
|
|
|
2,815
|
|
|
3,398
|
|
|
7,807
|
|
||||
Total operating revenues and other income
|
459,369
|
|
|
295,379
|
|
|
1,672,880
|
|
|
788,838
|
|
||||
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil, gas, and NGL production expense
|
127,638
|
|
|
122,651
|
|
|
365,917
|
|
|
385,073
|
|
||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
201,105
|
|
|
134,599
|
|
|
483,343
|
|
|
425,643
|
|
||||
Exploration
|
13,061
|
|
|
14,119
|
|
|
40,844
|
|
|
38,919
|
|
||||
Abandonment and impairment of unproved properties
|
9,055
|
|
|
—
|
|
|
26,615
|
|
|
157
|
|
||||
General and administrative
|
29,464
|
|
|
27,564
|
|
|
86,066
|
|
|
84,618
|
|
||||
Net derivative (gain) loss
|
178,026
|
|
|
80,599
|
|
|
249,304
|
|
|
(89,364
|
)
|
||||
Other operating expenses, net
|
9,664
|
|
|
999
|
|
|
14,219
|
|
|
10,109
|
|
||||
Total operating expenses
|
568,013
|
|
|
380,531
|
|
|
1,266,308
|
|
|
855,155
|
|
||||
Income (loss) from operations
|
(108,644
|
)
|
|
(85,152
|
)
|
|
406,572
|
|
|
(66,317
|
)
|
||||
Interest expense
|
(38,111
|
)
|
|
(44,091
|
)
|
|
(122,850
|
)
|
|
(135,639
|
)
|
||||
Loss on extinguishment of debt
|
(26,722
|
)
|
|
—
|
|
|
(26,722
|
)
|
|
(35
|
)
|
||||
Other non-operating income, net
|
806
|
|
|
861
|
|
|
3,017
|
|
|
1,581
|
|
||||
Income (loss) before income taxes
|
(172,671
|
)
|
|
(128,382
|
)
|
|
260,017
|
|
|
(200,410
|
)
|
||||
Income tax (expense) benefit
|
36,748
|
|
|
39,270
|
|
|
(61,342
|
)
|
|
65,825
|
|
||||
Net income (loss)
|
$
|
(135,923
|
)
|
|
$
|
(89,112
|
)
|
|
$
|
198,675
|
|
|
$
|
(134,585
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic weighted-average common shares outstanding
|
112,107
|
|
|
111,575
|
|
|
111,836
|
|
|
111,366
|
|
||||
Diluted weighted-average common shares outstanding
|
112,107
|
|
|
111,575
|
|
|
113,600
|
|
|
111,366
|
|
||||
Basic net income (loss) per common share
|
$
|
(1.21
|
)
|
|
$
|
(0.80
|
)
|
|
$
|
1.78
|
|
|
$
|
(1.21
|
)
|
Diluted net income (loss) per common share
|
$
|
(1.21
|
)
|
|
$
|
(0.80
|
)
|
|
$
|
1.75
|
|
|
$
|
(1.21
|
)
|
Dividends per common share
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
|
||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net income (loss)
|
$
|
(135,923
|
)
|
|
$
|
(89,112
|
)
|
|
$
|
198,675
|
|
|
$
|
(134,585
|
)
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
||||||||
Pension liability adjustment
|
263
|
|
|
(208
|
)
|
|
721
|
|
|
(651
|
)
|
||||
Total other comprehensive income (loss), net of tax
|
263
|
|
|
(208
|
)
|
|
721
|
|
|
(651
|
)
|
||||
Total comprehensive income (loss)
|
$
|
(135,660
|
)
|
|
$
|
(89,320
|
)
|
|
$
|
199,396
|
|
|
$
|
(135,236
|
)
|
|
For the Nine Months Ended
September 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
|
(as adjusted)
|
||||
Cash flows from operating activities:
|
|
|
|
||||
Net income (loss)
|
$
|
198,675
|
|
|
$
|
(134,585
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
||||
Net (gain) loss on divestiture activity
|
(425,656
|
)
|
|
131,565
|
|
||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
483,343
|
|
|
425,643
|
|
||
Abandonment and impairment of unproved properties
|
26,615
|
|
|
157
|
|
||
Stock-based compensation expense
|
17,680
|
|
|
16,160
|
|
||
Net derivative (gain) loss
|
249,304
|
|
|
(89,364
|
)
|
||
Derivative settlement gain (loss)
|
(101,911
|
)
|
|
29,402
|
|
||
Amortization of debt discount and deferred financing costs
|
11,542
|
|
|
12,478
|
|
||
Loss on extinguishment of debt
|
26,722
|
|
|
35
|
|
||
Deferred income taxes
|
60,672
|
|
|
(67,458
|
)
|
||
Other, net
|
(2,084
|
)
|
|
6,424
|
|
||
Net change in working capital
|
(3,725
|
)
|
|
40,153
|
|
||
Net cash provided by operating activities
|
541,177
|
|
|
370,610
|
|
||
|
|
|
|
||||
Cash flows from investing activities:
|
|
|
|
||||
Net proceeds from the sale of oil and gas properties
|
743,199
|
|
|
778,365
|
|
||
Capital expenditures
|
(1,032,588
|
)
|
|
(624,969
|
)
|
||
Acquisition of proved and unproved oil and gas properties
|
(24,571
|
)
|
|
(87,389
|
)
|
||
Net cash provided by (used in) investing activities
|
(313,960
|
)
|
|
66,007
|
|
||
|
|
|
|
||||
Cash flows from financing activities:
|
|
|
|
||||
Proceeds from credit facility
|
—
|
|
|
406,000
|
|
||
Repayment of credit facility
|
—
|
|
|
(406,000
|
)
|
||
Debt issuance costs related to credit facility
|
(4,771
|
)
|
|
—
|
|
||
Net proceeds from Senior Notes
|
492,079
|
|
|
—
|
|
||
Cash paid to repurchase Senior Notes, including premium
|
(844,984
|
)
|
|
(2,357
|
)
|
||
Net proceeds from sale of common stock
|
1,881
|
|
|
1,738
|
|
||
Dividends paid
|
(5,584
|
)
|
|
(5,563
|
)
|
||
Other, net
|
(2,975
|
)
|
|
(1,392
|
)
|
||
Net cash used in financing activities
|
(364,354
|
)
|
|
(7,574
|
)
|
||
|
|
|
|
||||
Net change in cash, cash equivalents, and restricted cash
(1)
|
(137,137
|
)
|
|
429,043
|
|
||
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)
|
$
|
176,806
|
|
|
$
|
441,415
|
|
(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 Nine Months Ended
September 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
|
(as adjusted)
|
||||
Operating activities:
|
|
|
|
||||
Cash paid for interest, net of capitalized interest
|
$
|
(124,435
|
)
|
|
$
|
(124,443
|
)
|
Net cash paid for income taxes
|
$
|
(9,085
|
)
|
|
$
|
(2,800
|
)
|
|
|
|
|
||||
Investing activities:
|
|
|
|
||||
Changes in capital expenditure accruals and other
|
$
|
19,811
|
|
|
$
|
2,788
|
|
|
|
|
|
||||
Supplemental non-cash investing activities:
|
|
|
|
||||
Carrying value of properties exchanged
|
$
|
95,121
|
|
|
$
|
283,651
|
|
|
|
|
|
||||
Supplemental non-cash financing activities:
|
|
|
|
||||
Non-cash loss on extinguishment of debt, net
|
$
|
6,334
|
|
|
$
|
22
|
|
Dividends declared, but not paid
|
$
|
5,607
|
|
|
$
|
5,581
|
|
|
For the Nine Months Ended
September 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
|
$
|
370,597
|
|
|
$
|
370,610
|
|
|
|
|
|
||||
Cash flows from investing activities:
|
|
|
|
||||
Acquisition deposit held in escrow
|
$
|
3,000
|
|
|
N/A
|
|
|
Net cash provided by (used in) investing activities
|
$
|
69,007
|
|
|
$
|
66,007
|
|
|
|
|
|
||||
Cash flows from financing activities:
|
|
|
|
||||
Cash paid for extinguishment of debt
(1)
|
N/A
|
|
|
$
|
(13
|
)
|
|
Net cash used in financing activities
|
$
|
(7,561
|
)
|
|
$
|
(7,574
|
)
|
|
|
|
|
||||
Net change in cash and cash equivalents
|
$
|
432,043
|
|
|
N/A
|
|
|
Net change in cash, cash equivalents, and restricted cash
|
N/A
|
|
|
$
|
429,043
|
|
|
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
|
$
|
441,415
|
|
|
N/A
|
|
|
Cash, cash equivalents, and restricted cash at end of period
|
N/A
|
|
|
$
|
441,415
|
|
(1)
|
Included as a component within the cash paid to repurchase Senior Notes, including premium line item on the accompanying statements of cash flows.
|
|
For the Three Months Ended September 30, 2017
|
|
For the Nine Months Ended September 30, 2017
|
||||||||||||
|
As Reported
|
|
As Adjusted
|
|
As Reported
|
|
As Adjusted
|
||||||||
|
(in thousands)
|
||||||||||||||
Operating expenses:
|
|
|
|
|
|
|
|
||||||||
Exploration
|
$
|
14,243
|
|
|
$
|
14,119
|
|
|
$
|
39,293
|
|
|
$
|
38,919
|
|
General and administrative
|
$
|
27,880
|
|
|
$
|
27,564
|
|
|
$
|
85,564
|
|
|
$
|
84,618
|
|
Total operating expenses
|
$
|
380,971
|
|
|
$
|
380,531
|
|
|
$
|
856,475
|
|
|
$
|
855,155
|
|
|
|
|
|
|
|
|
|
||||||||
Income (loss) from operations
|
$
|
(85,592
|
)
|
|
$
|
(85,152
|
)
|
|
$
|
(67,637
|
)
|
|
$
|
(66,317
|
)
|
|
|
|
|
|
|
|
|
||||||||
Other non-operating income, net
|
$
|
1,301
|
|
|
$
|
861
|
|
|
$
|
2,901
|
|
|
$
|
1,581
|
|
|
Permian
|
|
South Texas & Gulf Coast
|
|
Rocky Mountain
|
|
Total
|
||||||||||||||||||||||||
|
Three Months Ended September 30,
|
|
Three Months Ended September 30,
|
|
Three Months Ended September 30,
|
|
Three Months Ended September 30,
|
||||||||||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||||||
Oil, gas, and NGL production revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Oil production revenue
|
$
|
270,086
|
|
|
$
|
107,248
|
|
|
$
|
17,436
|
|
|
$
|
13,726
|
|
|
$
|
—
|
|
|
$
|
33,229
|
|
|
$
|
287,522
|
|
|
$
|
154,203
|
|
Gas production revenue
|
40,364
|
|
|
16,034
|
|
|
56,446
|
|
|
69,069
|
|
|
—
|
|
|
1,162
|
|
|
96,810
|
|
|
86,265
|
|
||||||||
NGL production revenue
|
563
|
|
|
151
|
|
|
73,487
|
|
|
53,023
|
|
|
—
|
|
|
817
|
|
|
74,050
|
|
|
53,991
|
|
||||||||
Total
|
$
|
311,013
|
|
|
$
|
123,433
|
|
|
$
|
147,369
|
|
|
$
|
135,818
|
|
|
$
|
—
|
|
|
$
|
35,208
|
|
|
$
|
458,382
|
|
|
$
|
294,459
|
|
Relative percentage
|
68
|
%
|
|
42
|
%
|
|
32
|
%
|
|
46
|
%
|
|
—
|
%
|
|
12
|
%
|
|
100
|
%
|
|
100
|
%
|
|
Permian
|
|
South Texas & Gulf Coast
|
|
Rocky Mountain
|
|
Total
|
||||||||||||||||||||||||
|
Nine Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||||||
Oil, gas, and NGL production revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Oil production revenue
|
$
|
703,516
|
|
|
$
|
267,301
|
|
|
$
|
56,365
|
|
|
$
|
65,662
|
|
|
$
|
54,851
|
|
|
$
|
117,738
|
|
|
$
|
814,732
|
|
|
$
|
450,701
|
|
Gas production revenue
|
96,974
|
|
|
40,280
|
|
|
161,414
|
|
|
245,030
|
|
|
1,595
|
|
|
3,846
|
|
|
259,983
|
|
|
289,156
|
|
||||||||
NGL production revenue
|
816
|
|
|
405
|
|
|
167,505
|
|
|
169,938
|
|
|
790
|
|
|
2,396
|
|
|
169,111
|
|
|
172,739
|
|
||||||||
Total
|
$
|
801,306
|
|
|
$
|
307,986
|
|
|
$
|
385,284
|
|
|
$
|
480,630
|
|
|
$
|
57,236
|
|
|
$
|
123,980
|
|
|
$
|
1,243,826
|
|
|
$
|
912,596
|
|
Relative percentage
|
64
|
%
|
|
34
|
%
|
|
31
|
%
|
|
53
|
%
|
|
5
|
%
|
|
13
|
%
|
|
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 of the facility and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue 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 September 30,
|
|
For the Nine Months Ended September 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Income (loss) before income taxes
(1)
|
$
|
—
|
|
|
$
|
7,593
|
|
|
$
|
(28,975
|
)
|
|
$
|
(478,572
|
)
|
(1)
|
Income (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
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Current portion of income tax (expense) benefit:
|
|
|
|
|
|
|
|
||||||||
Federal
|
$
|
—
|
|
|
$
|
2,832
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
(85
|
)
|
|
(230
|
)
|
|
(670
|
)
|
|
(1,633
|
)
|
||||
Deferred portion of income tax (expense) benefit
|
36,833
|
|
|
36,668
|
|
|
(60,672
|
)
|
|
67,458
|
|
||||
Income tax (expense) benefit
|
$
|
36,748
|
|
|
$
|
39,270
|
|
|
$
|
(61,342
|
)
|
|
$
|
65,825
|
|
Effective tax rate
|
21.3
|
%
|
|
30.6
|
%
|
|
23.6
|
%
|
|
32.8
|
%
|
Borrowing Base Utilization Percentage
|
|
<25%
|
|
≥25% <50%
|
|
≥50% <75%
|
|
≥75% <90%
|
|
≥90%
|
|||||
Eurodollar Loans
|
|
1.500
|
%
|
|
1.750
|
%
|
|
2.000
|
%
|
|
2.250
|
%
|
|
2.500
|
%
|
ABR Loans or Swingline Loans
|
|
0.500
|
%
|
|
0.750
|
%
|
|
1.000
|
%
|
|
1.250
|
%
|
|
1.500
|
%
|
Commitment Fee Rate
|
|
0.375
|
%
|
|
0.375
|
%
|
|
0.500
|
%
|
|
0.500
|
%
|
|
0.500
|
%
|
|
As of October 24, 2018
|
|
As of September 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
$6.7 million
and
$3.1 million
as of
September 30, 2018
, and
December 31, 2017
, respectively. These costs are being amortized over the term of the credit facility on a straight-line basis.
|
(2)
|
Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.
|
|
As of September 30, 2018
|
|
As of December 31, 2017
|
||||||||||||||||||||
|
Principal Amount
|
|
Unamortized Deferred Financing Costs
|
|
Principal Amount, Net of Unamortized Deferred Financing Costs
|
|
Principal Amount
|
|
Unamortized Deferred Financing Costs
|
|
Principal Amount, Net of Unamortized Deferred Financing Costs
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
6.50% Senior Notes due 2021
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
344,611
|
|
|
$
|
2,656
|
|
|
$
|
341,955
|
|
6.125% Senior Notes due 2022
|
476,796
|
|
|
4,171
|
|
|
472,625
|
|
|
561,796
|
|
|
5,800
|
|
|
555,996
|
|
||||||
6.50% Senior Notes due 2023
|
—
|
|
|
—
|
|
|
—
|
|
|
394,985
|
|
|
3,707
|
|
|
391,278
|
|
||||||
5.0% Senior Notes due 2024
|
500,000
|
|
|
4,919
|
|
|
495,081
|
|
|
500,000
|
|
|
5,610
|
|
|
494,390
|
|
||||||
5.625% Senior Notes due 2025
|
500,000
|
|
|
6,035
|
|
|
493,965
|
|
|
500,000
|
|
|
6,714
|
|
|
493,286
|
|
||||||
6.75% Senior Notes due 2026
|
500,000
|
|
|
6,615
|
|
|
493,385
|
|
|
500,000
|
|
|
7,242
|
|
|
492,758
|
|
||||||
6.625% Senior Notes due 2027
|
500,000
|
|
|
7,766
|
|
|
492,234
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total
|
$
|
2,476,796
|
|
|
$
|
29,506
|
|
|
$
|
2,447,290
|
|
|
$
|
2,801,392
|
|
|
$
|
31,729
|
|
|
$
|
2,769,663
|
|
|
As of September 30, 2018
|
|
As of December 31, 2017
|
||||
|
(in thousands)
|
||||||
Principal amount of Senior Convertible Notes
|
$
|
172,500
|
|
|
$
|
172,500
|
|
Unamortized debt discount
|
(24,316
|
)
|
|
(30,183
|
)
|
||
Unamortized deferred financing costs
|
(2,522
|
)
|
|
(3,210
|
)
|
||
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
$
|
145,662
|
|
|
$
|
139,107
|
|
|
PSUs
(1)
|
|
Weighted-Average Grant-Date Fair Value
|
||
Non-vested at beginning of year
|
1,533,491
|
|
$
|
22.97
|
|
Granted
|
572,924
|
|
$
|
24.45
|
|
Vested
|
(233,102)
|
|
$
|
44.25
|
|
Forfeited
|
(97,122)
|
|
$
|
22.89
|
|
Non-vested at end of quarter
|
1,776,191
|
|
$
|
20.66
|
|
(1)
|
The number of awards assumes a multiplier of
one
. The final number of shares of common stock issued may vary depending on the
three
-year performance multiplier which ranges from
zero
to
two
.
|
|
RSUs
|
|
Weighted-Average Grant-Date Fair Value
|
||
Non-vested at beginning of year
|
1,244,262
|
|
$
|
20.25
|
|
Granted
|
583,552
|
|
$
|
25.77
|
|
Vested
|
(407,529)
|
|
$
|
24.30
|
|
Forfeited
|
(112,141)
|
|
$
|
17.93
|
|
Non-vested at end of quarter
|
1,308,144
|
|
$
|
21.46
|
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Service cost
|
$
|
1,683
|
|
|
$
|
1,660
|
|
|
$
|
5,048
|
|
|
$
|
4,979
|
|
Interest cost
|
657
|
|
|
673
|
|
|
1,967
|
|
|
2,017
|
|
||||
Expected return on plan assets that reduces periodic pension benefit cost
|
(466
|
)
|
|
(561
|
)
|
|
(1,397
|
)
|
|
(1,683
|
)
|
||||
Amortization of prior service cost
|
4
|
|
|
4
|
|
|
13
|
|
|
13
|
|
||||
Amortization of net actuarial loss
|
331
|
|
|
324
|
|
|
995
|
|
|
973
|
|
||||
Net periodic benefit cost
|
$
|
2,209
|
|
|
$
|
2,100
|
|
|
$
|
6,626
|
|
|
$
|
6,299
|
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Net income (loss)
|
$
|
(135,923
|
)
|
|
$
|
(89,112
|
)
|
|
$
|
198,675
|
|
|
$
|
(134,585
|
)
|
|
|
|
|
|
|
|
|
||||||||
Basic weighted-average common shares outstanding
|
112,107
|
|
|
111,575
|
|
|
111,836
|
|
|
111,366
|
|
||||
Dilutive effect of non-vested RSUs and contingent PSUs
|
—
|
|
|
—
|
|
|
1,764
|
|
|
—
|
|
||||
Dilutive effect of Senior Convertible Notes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Diluted weighted-average common shares outstanding
|
112,107
|
|
|
111,575
|
|
|
113,600
|
|
|
111,366
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Basic net income (loss) per common share
|
$
|
(1.21
|
)
|
|
$
|
(0.80
|
)
|
|
$
|
1.78
|
|
|
$
|
(1.21
|
)
|
Diluted net income (loss) per common share
|
$
|
(1.21
|
)
|
|
$
|
(0.80
|
)
|
|
$
|
1.75
|
|
|
$
|
(1.21
|
)
|
Contract Period
|
|
NYMEX WTI Volumes
|
|
Weighted-Average
Contract Price
|
|||
|
|
(MBbl)
|
|
(per Bbl)
|
|||
Fourth quarter 2018
|
|
1,894
|
|
|
$
|
49.87
|
|
2019
|
|
3,733
|
|
|
$
|
59.80
|
|
2020
|
|
2,491
|
|
|
$
|
65.68
|
|
Total
|
|
8,118
|
|
|
|
Contract Period
|
|
NYMEX WTI
Volumes
|
|
Weighted-
Average Floor
Price
|
|
Weighted-
Average Ceiling
Price
|
|||||
|
|
(MBbl)
|
|
(per Bbl)
|
|
(per Bbl)
|
|||||
Fourth quarter 2018
|
|
2,222
|
|
|
$
|
50.00
|
|
|
$
|
58.44
|
|
2019
|
|
10,055
|
|
|
$
|
50.59
|
|
|
$
|
63.62
|
|
2020
|
|
1,165
|
|
|
$
|
55.00
|
|
|
$
|
66.47
|
|
Total
|
|
13,442
|
|
|
|
|
|
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)
|
||||||
Fourth quarter 2018
|
|
3,327
|
|
|
$
|
(1.08
|
)
|
|
—
|
|
|
$
|
—
|
|
2019
|
|
11,217
|
|
|
$
|
(3.36
|
)
|
|
—
|
|
|
$
|
—
|
|
2020
|
|
10,960
|
|
|
$
|
(1.05
|
)
|
|
1,840
|
|
|
$
|
(8.01
|
)
|
2021
|
|
—
|
|
|
$
|
—
|
|
|
3,650
|
|
|
$
|
(7.86
|
)
|
2022
|
|
—
|
|
|
$
|
—
|
|
|
3,650
|
|
|
$
|
(7.78
|
)
|
Total
|
|
25,504
|
|
|
|
|
9,140
|
|
|
|
(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)
|
|||||||||
Fourth quarter 2018
|
|
28,204
|
|
|
$
|
3.27
|
|
|
(7,210
|
)
|
|
$
|
4.27
|
|
|
20,994
|
|
|
$
|
2.92
|
|
2019
|
|
50,021
|
|
|
$
|
3.58
|
|
|
(24,415
|
)
|
|
$
|
4.34
|
|
|
25,606
|
|
|
$
|
2.85
|
|
2020
|
|
2,942
|
|
|
$
|
2.82
|
|
|
—
|
|
|
$
|
—
|
|
|
2,942
|
|
|
$
|
2.82
|
|
Total
|
|
81,167
|
|
|
|
|
(31,625
|
)
|
|
|
|
49,542
|
|
|
|
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
|
|
•
|
fixed price NYMEX WTI-ICE Brent basis swap contracts for 2020 for a total of
0.9
MMBbl of oil production at contract prices ranging from
($8.05)
per Bbl to
($8.10)
per Bbl;
|
•
|
IF HSC swap contracts for 2019 for a total of
15,769
BBtu of natural gas production at contract prices ranging from
$2.80
per MMBtu to
$3.42
per MMBtu;
|
•
|
fixed price OPIS Propane Mont Belvieu Non-TET swap contract for the fourth quarter of 2018 for a total of
0.1
MMBbl of propane production at a contract price of
$45.59
per Bbl; and
|
•
|
fixed price OPIS Propane Mont Belvieu Non-TET swap contracts for 2019 for a total of
0.4
MMBbl of propane production at a contract price of
$40.11
per Bbl.
|
|
As of September 30, 2018
|
|
As of December 31, 2017
|
||||
|
(in thousands)
|
||||||
Derivative assets:
|
|
|
|
||||
Current assets
|
$
|
81,163
|
|
|
$
|
64,266
|
|
Noncurrent assets
|
8,853
|
|
|
40,362
|
|
||
Total derivative assets
|
$
|
90,016
|
|
|
$
|
104,628
|
|
Derivative liabilities:
|
|
|
|
||||
Current liabilities
|
$
|
304,159
|
|
|
$
|
172,582
|
|
Noncurrent liabilities
|
72,605
|
|
|
71,402
|
|
||
Total derivative liabilities
|
$
|
376,764
|
|
|
$
|
243,984
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||
|
As of
|
|
As of
|
||||||||||||
|
September 30,
2018 |
|
December 31, 2017
|
|
September 30,
2018 |
|
December 31, 2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Gross amounts presented in the accompanying balance sheets
|
$
|
90,016
|
|
|
$
|
104,628
|
|
|
$
|
(376,764
|
)
|
|
$
|
(243,984
|
)
|
Amounts not offset in the accompanying balance sheets
|
(90,016
|
)
|
|
(100,035
|
)
|
|
90,016
|
|
|
100,035
|
|
||||
Net amounts
|
$
|
—
|
|
|
$
|
4,593
|
|
|
$
|
(286,748
|
)
|
|
$
|
(143,949
|
)
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Derivative settlement (gain) loss:
|
|
|
|
|
|
|
|
||||||||
Oil contracts
|
$
|
16,798
|
|
|
$
|
2,472
|
|
|
$
|
61,976
|
|
|
$
|
14,310
|
|
Gas contracts
|
802
|
|
|
(24,088
|
)
|
|
(4,851
|
)
|
|
(63,345
|
)
|
||||
NGL contracts
|
23,118
|
|
|
8,524
|
|
|
44,786
|
|
|
19,633
|
|
||||
Total derivative settlement (gain) loss
|
$
|
40,718
|
|
|
$
|
(13,092
|
)
|
|
$
|
101,911
|
|
|
$
|
(29,402
|
)
|
|
|
|
|
|
|
|
|
||||||||
Net derivative (gain) loss:
|
|
|
|
|
|
|
|
||||||||
Oil contracts
|
$
|
110,413
|
|
|
$
|
45,874
|
|
|
$
|
146,781
|
|
|
$
|
(41,910
|
)
|
Gas contracts
|
4,309
|
|
|
(6,068
|
)
|
|
21,299
|
|
|
(56,574
|
)
|
||||
NGL contracts
|
63,304
|
|
|
40,793
|
|
|
81,224
|
|
|
9,120
|
|
||||
Total net derivative (gain) loss
|
$
|
178,026
|
|
|
$
|
80,599
|
|
|
$
|
249,304
|
|
|
$
|
(89,364
|
)
|
•
|
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)
|
$
|
—
|
|
|
$
|
90,016
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
376,764
|
|
|
$
|
—
|
|
(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 September 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
|
|
|
$
|
351,682
|
|
6.125% Senior Notes due 2022
|
$
|
476,796
|
|
|
$
|
491,076
|
|
|
$
|
561,796
|
|
|
$
|
571,627
|
|
6.50% Senior Notes due 2023
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
394,985
|
|
|
$
|
403,434
|
|
5.0% Senior Notes due 2024
|
$
|
500,000
|
|
|
$
|
491,000
|
|
|
$
|
500,000
|
|
|
$
|
483,440
|
|
5.625% Senior Notes due 2025
|
$
|
500,000
|
|
|
$
|
498,125
|
|
|
$
|
500,000
|
|
|
$
|
494,355
|
|
6.75% Senior Notes due 2026
|
$
|
500,000
|
|
|
$
|
522,150
|
|
|
$
|
500,000
|
|
|
$
|
516,350
|
|
6.625% Senior Notes due 2027
|
$
|
500,000
|
|
|
$
|
517,250
|
|
|
$
|
—
|
|
|
$
|
—
|
|
1.50% Senior Convertible Notes due 2021
|
$
|
172,500
|
|
|
$
|
191,044
|
|
|
$
|
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.
|
•
|
Average net daily production for the three months ended
September 30, 2018
, was
130.2
MBOE, compared with
116.0
MBOE for the same period in 2017. The increase was primarily driven by our Permian region, which had a
100 percent
increase in production volumes in the third quarter of 2018 compared to the same period in
2017
. Please refer to
A Three-Month and Nine-Month Overview of Selected Production and Financial Information, Including Trends
below for additional discussion on production.
|
•
|
Net cash provided by operating activities was
$229.7 million
for the three months ended
September 30, 2018
, compared with
$128.5 million
for the same period in
2017
. The increase in net cash provided by operating activities for the three months ended
September 30, 2018
, was primarily the result of a
48 percent
growth in higher margin oil production, which drove our
39 percent
increase in pre-hedge realized price and
12 percent
increase in net equivalent volumes produced. Partially offsetting the increase was a realized settlement loss on derivatives of
$40.7 million
during the third quarter of 2018, compared to a realized settlement gain of
$13.1 million
during the same period in
2017
. Please refer to
Overview of Liquidity and Capital Resources
below for additional discussion of our sources and uses of cash.
|
•
|
We recorded a net loss of
$135.9 million
, or
$1.21
per diluted share, for the three months ended
September 30, 2018
, compared with a net loss of
$89.1 million
, or
$0.80
per diluted share, for the same period in
2017
. Our net loss for the third quarter of 2018, was driven primarily by net derivative losses of
$178.0 million
and a loss on extinguishment of debt of
$26.7 million
. Please refer to
Comparison of Financial Results and Trends Between the Three Months and Nine Months Ended September 30, 2018, and 2017
below for additional discussion regarding the components of net income (loss) for each of the periods presented.
|
•
|
Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended
September 30, 2018
, was
$256.1 million
, compared with
$164.3 million
for the same period in
2017
. The increase in the third quarter of 2018 compared to the same period in
2017
was driven largely by increased production revenue, which was partially offset by increased losses
|
•
|
2021 Senior Notes Redemption.
On July 16, 2018, we redeemed all of the
$344.6 million
principal outstanding of our 2021 Senior Notes for total cash consideration, including the premium paid and accrued interest, of
$355.9 million
. Redemption of the 2021 Senior Notes resulted in a loss on extinguishment of debt of
$9.8 million
for the quarter ended September 30, 2018.
|
•
|
2027 Senior Notes Issuance.
On
August 20, 2018
, we issued
$500.0 million
in aggregate principal amount of
6.625%
Senior Notes due 2027. The 2027 Senior Notes were issued at par and mature on January 15, 2027. We received net proceeds of
$492.1 million
after deducting fees of
$7.9 million
, which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. The net proceeds were used to fund the Tender Offer and 2023 Senior Notes Redemption discussed below.
|
•
|
Tender Offer and Redemption of our 2023 Senior Notes and a Portion of our 2022 Senior Notes.
Concurrently with our 2027 Senior Notes offering, as discussed above, we announced our Tender Offer for all of our 2023 Senior Notes and a portion of our 2022 Senior Notes, and our intention to redeem any remaining 2023 Senior Notes outstanding upon completion of the Tender Offer. Upon completing the Tender Offer and subsequent redemption, we retired all of the
$395.0 million
principal outstanding of our 2023 Senior Notes and
$85.0 million
principal outstanding of our 2022 Senior Notes. Consideration paid to complete these transactions totaled
$497.8 million
, including the premium paid and accrued interest. The Tender Offer and subsequent redemption of the remaining 2023 Senior Notes resulted in a loss on extinguishment of debt of
$16.9 million
for the quarter ended September 30, 2018.
|
•
|
Credit Agreement.
On
September 28, 2018
, we entered into the Credit Agreement with our lenders which provides for a senior secured revolving credit facility with a maximum loan amount of
$2.5 billion
, an initial borrowing base of
$1.5 billion
, and initial aggregate lender commitments totaling
$1.0 billion
. The Credit Agreement is scheduled to mature on
September 28, 2023
. The maturity date could, however, occur earlier on August 16, 2022, to the extent we have not completed certain repurchase, redemption, or refinancing activities associated with our 2022 Senior Notes as outlined in the Credit Agreement.
|
|
Permian
|
|
South Texas & Gulf Coast
|
|
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
|
|
Wells drilled
|
35
|
|
|
34
|
|
|
8
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
39
|
|
Wells completed
|
(29
|
)
|
|
(28
|
)
|
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(34
|
)
|
|
(33
|
)
|
Other
(1)
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Wells drilled but not completed at September 30, 2018
|
56
|
|
|
55
|
|
|
36
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
92
|
|
|
85
|
|
(1)
|
Reflects net working interest changes resulting from normal business operations.
|
(2)
|
We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there has been no 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 September 30,
|
|
Three Months Ended September 30,
|
|
Three Months Ended September 30,
|
|
Three Months Ended September 30,
|
||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (MMBbl)
|
4.8
|
|
|
2.3
|
|
|
0.3
|
|
|
0.4
|
|
|
—
|
|
|
0.7
|
|
|
5.0
|
|
|
3.4
|
|
Gas (Bcf)
|
7.1
|
|
|
3.9
|
|
|
20.1
|
|
|
24.2
|
|
|
—
|
|
|
1.0
|
|
|
27.2
|
|
|
29.1
|
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
2.4
|
|
|
2.4
|
|
|
—
|
|
|
—
|
|
|
2.4
|
|
|
2.4
|
|
Equivalent (MMBOE)
|
6.0
|
|
|
3.0
|
|
|
6.0
|
|
|
6.7
|
|
|
—
|
|
|
1.0
|
|
|
12.0
|
|
|
10.7
|
|
Avg. daily equivalents (MBOE/d)
|
64.8
|
|
|
32.3
|
|
|
65.4
|
|
|
73.3
|
|
|
—
|
|
|
10.4
|
|
|
130.2
|
|
|
116.0
|
|
Relative percentage
|
50
|
%
|
|
28
|
%
|
|
50
|
%
|
|
63
|
%
|
|
—
|
%
|
|
9
|
%
|
|
100
|
%
|
|
100
|
%
|
(1)
|
We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.
|
|
Permian
|
|
South Texas & Gulf Coast
|
|
Rocky Mountain
(1)
|
|
Total
|
||||||||||||||||
|
Nine Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (MMBbl)
|
11.8
|
|
|
5.6
|
|
|
1.0
|
|
|
1.6
|
|
|
0.9
|
|
|
2.6
|
|
|
13.7
|
|
|
9.8
|
|
Gas (Bcf)
|
18.9
|
|
|
10.1
|
|
|
57.6
|
|
|
83.8
|
|
|
1.2
|
|
|
3.1
|
|
|
77.7
|
|
|
97.0
|
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
5.9
|
|
|
8.0
|
|
|
—
|
|
|
0.1
|
|
|
6.0
|
|
|
8.1
|
|
Equivalent (MMBOE)
|
15.0
|
|
|
7.3
|
|
|
16.5
|
|
|
23.5
|
|
|
1.1
|
|
|
3.2
|
|
|
32.6
|
|
|
34.1
|
|
Avg. daily equivalents (MBOE/d)
|
54.9
|
|
|
26.9
|
|
|
60.4
|
|
|
86.2
|
|
|
4.1
|
|
|
11.8
|
|
|
119.4
|
|
|
124.9
|
|
Relative percentage
|
46
|
%
|
|
22
|
%
|
|
51
|
%
|
|
69
|
%
|
|
3
|
%
|
|
9
|
%
|
|
100
|
%
|
|
100
|
%
|
(1)
|
We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.
|
|
For the Three Months Ended
|
||||||||||
|
September 30, 2018
|
|
June 30, 2018
|
|
September 30, 2017
|
||||||
Oil (per Bbl):
|
|
|
|
|
|
||||||
Average NYMEX contract monthly price
|
$
|
69.50
|
|
|
$
|
67.88
|
|
|
$
|
48.20
|
|
Realized price, before the effect of derivative settlements
|
$
|
56.96
|
|
|
$
|
61.02
|
|
|
$
|
45.20
|
|
Effect of oil derivative settlements
|
$
|
(3.32
|
)
|
|
$
|
(5.60
|
)
|
|
$
|
(0.73
|
)
|
Gas:
|
|
|
|
|
|
||||||
Average NYMEX monthly settle price (per MMBtu)
|
$
|
2.90
|
|
|
$
|
2.80
|
|
|
$
|
3.00
|
|
Realized price, before the effect of derivative settlements (per Mcf)
|
$
|
3.56
|
|
|
$
|
3.32
|
|
|
$
|
2.96
|
|
Effect of gas derivative settlements (per Mcf)
|
$
|
(0.03
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
0.83
|
|
NGLs (per Bbl):
|
|
|
|
|
|
||||||
Average OPIS price
(1)
|
$
|
37.97
|
|
|
$
|
33.10
|
|
|
$
|
27.55
|
|
Realized price, before the effect of derivative settlements
|
$
|
30.77
|
|
|
$
|
27.55
|
|
|
$
|
22.40
|
|
Effect of NGL derivative settlements
|
$
|
(9.61
|
)
|
|
$
|
(6.04
|
)
|
|
$
|
(3.54
|
)
|
(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 October 24, 2018
|
|
As of September 30, 2018
|
||||
NYMEX WTI oil (per Bbl)
|
$
|
67.07
|
|
|
$
|
72.28
|
|
NYMEX Henry Hub gas (per MMBtu)
|
$
|
2.90
|
|
|
$
|
2.85
|
|
OPIS NGLs (per Bbl)
|
$
|
31.27
|
|
|
$
|
38.94
|
|
|
For the Three Months Ended
|
||||||||||||||
|
September 30,
|
|
June 30,
|
|
March 31,
|
|
December 31,
|
||||||||
|
2018
|
|
2018
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
Production (MMBOE)
|
12.0
|
|
|
10.5
|
|
|
10.1
|
|
|
10.4
|
|
||||
Oil, gas, and NGL production revenue
|
$
|
458.4
|
|
|
$
|
402.6
|
|
|
$
|
382.9
|
|
|
$
|
341.2
|
|
Oil, gas, and NGL production expense
|
$
|
127.6
|
|
|
$
|
117.4
|
|
|
$
|
120.9
|
|
|
$
|
122.8
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
201.1
|
|
|
$
|
151.8
|
|
|
$
|
130.5
|
|
|
$
|
131.4
|
|
Exploration
(1)
|
$
|
13.1
|
|
|
$
|
14.1
|
|
|
$
|
13.7
|
|
|
$
|
15.8
|
|
General and administrative
(1)
|
$
|
29.5
|
|
|
$
|
28.9
|
|
|
$
|
27.7
|
|
|
$
|
32.7
|
|
Net income (loss)
|
$
|
(135.9
|
)
|
|
$
|
17.2
|
|
|
$
|
317.4
|
|
|
$
|
(26.3
|
)
|
(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
|
||||||||||||||
|
September 30,
|
|
June 30,
|
|
March 31,
|
|
December 31,
|
||||||||
|
2018
|
|
2018
|
|
2018
|
|
2017
|
||||||||
Average net daily production equivalent (MBOE per day)
|
130.2
|
|
|
115.2
|
|
|
112.7
|
|
|
112.6
|
|
||||
Lease operating expense (per BOE)
|
$
|
4.41
|
|
|
$
|
4.66
|
|
|
$
|
4.95
|
|
|
$
|
5.10
|
|
Transportation costs (per BOE)
|
$
|
4.20
|
|
|
$
|
4.47
|
|
|
$
|
4.63
|
|
|
$
|
5.01
|
|
Production taxes as a percent of oil, gas, and NGL production revenue
|
4.1
|
%
|
|
4.3
|
%
|
|
4.4
|
%
|
|
4.3
|
%
|
||||
Ad valorem tax expense (per BOE)
|
$
|
0.45
|
|
|
$
|
0.41
|
|
|
$
|
0.67
|
|
|
$
|
0.33
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
|
$
|
16.78
|
|
|
$
|
14.48
|
|
|
$
|
12.87
|
|
|
$
|
12.69
|
|
General and administrative (per BOE)
(1)
|
$
|
2.46
|
|
|
$
|
2.76
|
|
|
$
|
2.73
|
|
|
$
|
3.15
|
|
(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 September 30,
|
|
Amount Change Between Periods
|
|
Percent Change Between Periods
|
|
For the Nine Months Ended September 30,
|
|
Amount Change Between Periods
|
|
Percent Change Between Periods
|
||||||||||||||||||
|
2018
|
|
2017
|
|
|
2018
|
|
2017
|
|
||||||||||||||||||||
Net production volumes:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MMBbl)
|
5.0
|
|
|
3.4
|
|
|
1.6
|
|
|
48
|
%
|
|
13.7
|
|
|
9.8
|
|
|
3.8
|
|
|
39
|
%
|
||||||
Gas (Bcf)
|
27.2
|
|
|
29.1
|
|
|
(1.9
|
)
|
|
(7
|
)%
|
|
77.7
|
|
|
97.0
|
|
|
(19.3
|
)
|
|
(20
|
)%
|
||||||
NGLs (MMBbl)
|
2.4
|
|
|
2.4
|
|
|
—
|
|
|
—
|
%
|
|
6.0
|
|
|
8.1
|
|
|
(2.1
|
)
|
|
(26
|
)%
|
||||||
Equivalent (MMBOE)
|
12.0
|
|
|
10.7
|
|
|
1.3
|
|
|
12
|
%
|
|
32.6
|
|
|
34.1
|
|
|
(1.5
|
)
|
|
(4
|
)%
|
||||||
Average net daily production:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MBbl per day)
|
54.9
|
|
|
37.1
|
|
|
17.8
|
|
|
48
|
%
|
|
50.1
|
|
|
36.1
|
|
|
14.0
|
|
|
39
|
%
|
||||||
Gas (MMcf per day)
|
295.3
|
|
|
316.1
|
|
|
(20.8
|
)
|
|
(7
|
)%
|
|
284.7
|
|
|
355.4
|
|
|
(70.7
|
)
|
|
(20
|
)%
|
||||||
NGLs (MBbl per day)
|
26.2
|
|
|
26.2
|
|
|
—
|
|
|
—
|
%
|
|
21.9
|
|
|
29.6
|
|
|
(7.7
|
)
|
|
(26
|
)%
|
||||||
Equivalent (MBOE per day)
|
130.2
|
|
|
116.0
|
|
|
14.2
|
|
|
12
|
%
|
|
119.4
|
|
|
124.9
|
|
|
(5.5
|
)
|
|
(4
|
)%
|
||||||
Oil, gas, and NGL production revenue (in millions):
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil production revenue
|
$
|
287.5
|
|
|
$
|
154.2
|
|
|
$
|
133.3
|
|
|
86
|
%
|
|
$
|
814.7
|
|
|
$
|
450.7
|
|
|
$
|
364.0
|
|
|
81
|
%
|
Gas production revenue
|
96.8
|
|
|
86.3
|
|
|
10.6
|
|
|
12
|
%
|
|
260.0
|
|
|
289.2
|
|
|
(29.2
|
)
|
|
(10
|
)%
|
||||||
NGL production revenue
|
74.1
|
|
|
54.0
|
|
|
20.0
|
|
|
37
|
%
|
|
169.1
|
|
|
172.7
|
|
|
(3.6
|
)
|
|
(2
|
)%
|
||||||
Total oil, gas, and NGL production revenue
|
$
|
458.4
|
|
|
$
|
294.5
|
|
|
$
|
163.9
|
|
|
56
|
%
|
|
$
|
1,243.8
|
|
|
$
|
912.6
|
|
|
$
|
331.2
|
|
|
36
|
%
|
Oil, gas, and NGL production expense (in millions):
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expense
|
$
|
52.8
|
|
|
$
|
51.4
|
|
|
$
|
1.5
|
|
|
3
|
%
|
|
$
|
151.9
|
|
|
$
|
144.1
|
|
|
$
|
7.8
|
|
|
5
|
%
|
Transportation costs
|
50.4
|
|
|
55.9
|
|
|
(5.5
|
)
|
|
(10
|
)%
|
|
144.1
|
|
|
191.7
|
|
|
(47.6
|
)
|
|
(25
|
)%
|
||||||
Production taxes
|
19.0
|
|
|
12.4
|
|
|
6.6
|
|
|
54
|
%
|
|
53.4
|
|
|
37.8
|
|
|
15.6
|
|
|
41
|
%
|
||||||
Ad valorem tax expense
|
5.4
|
|
|
3.0
|
|
|
2.4
|
|
|
79
|
%
|
|
16.5
|
|
|
11.5
|
|
|
5.0
|
|
|
44
|
%
|
||||||
Total oil, gas, and NGL production expense
|
$
|
127.6
|
|
|
$
|
122.7
|
|
|
$
|
5.0
|
|
|
4
|
%
|
|
$
|
365.9
|
|
|
$
|
385.1
|
|
|
$
|
(19.2
|
)
|
|
(5
|
)%
|
Realized price (before the effect of derivative settlements):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (per Bbl)
|
$
|
56.96
|
|
|
$
|
45.20
|
|
|
$
|
11.76
|
|
|
26
|
%
|
|
$
|
59.60
|
|
|
$
|
45.77
|
|
|
$
|
13.83
|
|
|
30
|
%
|
Gas (per Mcf)
|
$
|
3.56
|
|
|
$
|
2.96
|
|
|
$
|
0.60
|
|
|
20
|
%
|
|
$
|
3.35
|
|
|
$
|
2.98
|
|
|
$
|
0.37
|
|
|
12
|
%
|
NGLs (per Bbl)
|
$
|
30.77
|
|
|
$
|
22.40
|
|
|
$
|
8.37
|
|
|
37
|
%
|
|
$
|
28.28
|
|
|
$
|
21.36
|
|
|
$
|
6.92
|
|
|
32
|
%
|
Per BOE
|
$
|
38.26
|
|
|
$
|
27.59
|
|
|
$
|
10.67
|
|
|
39
|
%
|
|
$
|
38.15
|
|
|
$
|
26.76
|
|
|
$
|
11.39
|
|
|
43
|
%
|
Per BOE data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expense
|
$
|
4.41
|
|
|
$
|
4.81
|
|
|
$
|
(0.40
|
)
|
|
(8
|
)%
|
|
$
|
4.66
|
|
|
$
|
4.22
|
|
|
$
|
0.44
|
|
|
10
|
%
|
Transportation costs
|
$
|
4.20
|
|
|
$
|
5.24
|
|
|
$
|
(1.04
|
)
|
|
(20
|
)%
|
|
$
|
4.42
|
|
|
$
|
5.62
|
|
|
$
|
(1.20
|
)
|
|
(21
|
)%
|
Production taxes
|
$
|
1.58
|
|
|
$
|
1.15
|
|
|
$
|
0.43
|
|
|
37
|
%
|
|
$
|
1.64
|
|
|
$
|
1.11
|
|
|
$
|
0.53
|
|
|
48
|
%
|
Ad valorem tax expense
|
$
|
0.45
|
|
|
$
|
0.29
|
|
|
$
|
0.16
|
|
|
55
|
%
|
|
$
|
0.51
|
|
|
$
|
0.34
|
|
|
$
|
0.17
|
|
|
50
|
%
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
16.78
|
|
|
$
|
12.61
|
|
|
$
|
4.17
|
|
|
33
|
%
|
|
$
|
14.82
|
|
|
$
|
12.48
|
|
|
$
|
2.34
|
|
|
19
|
%
|
General and administrative
(2)
|
$
|
2.46
|
|
|
$
|
2.58
|
|
|
$
|
(0.12
|
)
|
|
(5
|
)%
|
|
$
|
2.64
|
|
|
$
|
2.48
|
|
|
$
|
0.16
|
|
|
6
|
%
|
Derivative settlement gain (loss)
(3)
|
$
|
(3.40
|
)
|
|
$
|
1.23
|
|
|
$
|
(4.63
|
)
|
|
(376
|
)%
|
|
$
|
(3.13
|
)
|
|
$
|
0.86
|
|
|
$
|
(3.99
|
)
|
|
(464
|
)%
|
Earnings per share information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Basic weighted-average common shares outstanding (in thousands)
|
112,107
|
|
|
111,575
|
|
|
532
|
|
|
—
|
%
|
|
111,836
|
|
|
111,366
|
|
|
470
|
|
|
—
|
%
|
||||||
Diluted weighted-average common shares outstanding (in thousands)
|
112,107
|
|
|
111,575
|
|
|
532
|
|
|
—
|
%
|
|
113,600
|
|
|
111,366
|
|
|
2,234
|
|
|
2
|
%
|
||||||
Basic net income (loss) per common share
|
$
|
(1.21
|
)
|
|
$
|
(0.80
|
)
|
|
$
|
(0.41
|
)
|
|
(51
|
)%
|
|
$
|
1.78
|
|
|
$
|
(1.21
|
)
|
|
$
|
2.99
|
|
|
247
|
%
|
Diluted net income (loss) per common share
|
$
|
(1.21
|
)
|
|
$
|
(0.80
|
)
|
|
$
|
(0.41
|
)
|
|
(51
|
)%
|
|
$
|
1.75
|
|
|
$
|
(1.21
|
)
|
|
$
|
2.96
|
|
|
245
|
%
|
(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
nine
months ended
September 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
|
|
Nine Months Ended
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||
|
(MMBOE)
|
|
(in millions)
|
|
(in millions)
|
||||||||||||||||
Permian
|
3.0
|
|
|
7.6
|
|
|
$
|
187.6
|
|
|
$
|
493.3
|
|
|
$
|
26.0
|
|
|
$
|
67.6
|
|
South Texas & Gulf Coast
|
(0.7
|
)
|
|
(7.0
|
)
|
|
11.6
|
|
|
(95.3
|
)
|
|
(5.1
|
)
|
|
(57.5
|
)
|
||||
Rocky Mountain
(1)
|
(1.0
|
)
|
|
(2.1
|
)
|
|
(35.2
|
)
|
|
(66.7
|
)
|
|
(15.9
|
)
|
|
(29.3
|
)
|
||||
Total
|
1.3
|
|
|
(1.5
|
)
|
|
$
|
163.9
|
|
|
$
|
331.2
|
|
|
$
|
5.0
|
|
|
$
|
(19.2
|
)
|
(1)
|
We divested our remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
201.1
|
|
|
$
|
134.6
|
|
|
$
|
483.3
|
|
|
$
|
425.6
|
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
Exploration
(1)
|
$
|
13.1
|
|
|
$
|
14.1
|
|
|
$
|
40.8
|
|
|
$
|
38.9
|
|
(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
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
Abandonment and impairment of unproved properties
|
$
|
9.1
|
|
|
$
|
—
|
|
|
$
|
26.6
|
|
|
$
|
0.2
|
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions)
|
||||||||||||||
General and administrative
(1)
|
$
|
29.5
|
|
|
$
|
27.6
|
|
|
$
|
86.1
|
|
|
$
|
84.6
|
|
(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
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in millions, except tax rate)
|
||||||||||||||
Income tax (expense) benefit
|
$
|
36.7
|
|
|
$
|
39.3
|
|
|
$
|
(61.3
|
)
|
|
$
|
65.8
|
|
Effective tax rate
|
21.3
|
%
|
|
30.6
|
%
|
|
23.6
|
%
|
|
32.8
|
%
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
Weighted-average interest rate
|
6.4
|
%
|
|
6.3
|
%
|
|
6.4
|
%
|
|
6.5
|
%
|
Weighted-average borrowing rate
|
5.7
|
%
|
|
5.7
|
%
|
|
5.8
|
%
|
|
5.8
|
%
|
|
For the Nine Months Ended
September 30, |
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Net cash provided by operating activities
|
$
|
541.2
|
|
|
$
|
370.6
|
|
|
For the Nine Months Ended
September 30, |
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Net cash provided by (used in) investing activities
|
$
|
(314.0
|
)
|
|
$
|
66.0
|
|
|
For the Nine Months Ended
September 30, |
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Net cash used in financing activities
|
$
|
(364.4
|
)
|
|
$
|
(7.6
|
)
|
|
For the Three Months Ended
September 30, |
|
For the Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(in thousands)
|
||||||||||||||
Net income (loss) (GAAP)
|
$
|
(135,923
|
)
|
|
$
|
(89,112
|
)
|
|
$
|
198,675
|
|
|
$
|
(134,585
|
)
|
Interest expense
|
38,111
|
|
|
44,091
|
|
|
122,850
|
|
|
135,639
|
|
||||
Interest income
(1)
|
(1,332
|
)
|
|
(1,301
|
)
|
|
(4,595
|
)
|
|
(2,901
|
)
|
||||
Income tax expense (benefit)
|
(36,748
|
)
|
|
(39,270
|
)
|
|
61,342
|
|
|
(65,825
|
)
|
||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
201,105
|
|
|
134,599
|
|
|
483,343
|
|
|
425,643
|
|
||||
Exploration
(2) (3)
|
11,490
|
|
|
12,624
|
|
|
36,768
|
|
|
35,021
|
|
||||
Abandonment and impairment of unproved properties
|
9,055
|
|
|
—
|
|
|
26,615
|
|
|
157
|
|
||||
Stock-based compensation expense
|
7,004
|
|
|
6,347
|
|
|
17,680
|
|
|
16,160
|
|
||||
Net derivative (gain) loss
|
178,026
|
|
|
80,599
|
|
|
249,304
|
|
|
(89,364
|
)
|
||||
Derivative settlement gain (loss)
|
(40,718
|
)
|
|
13,092
|
|
|
(101,911
|
)
|
|
29,402
|
|
||||
Net (gain) loss on divestiture activity
|
(786
|
)
|
|
1,895
|
|
|
(425,656
|
)
|
|
131,565
|
|
||||
Loss on extinguishment of debt
|
26,722
|
|
|
—
|
|
|
26,722
|
|
|
35
|
|
||||
Other, net
|
67
|
|
|
785
|
|
|
76
|
|
|
9,426
|
|
||||
Adjusted EBITDAX (non-GAAP)
(3)
|
256,073
|
|
|
164,349
|
|
|
691,213
|
|
|
490,373
|
|
||||
Interest expense
|
(38,111
|
)
|
|
(44,091
|
)
|
|
(122,850
|
)
|
|
(135,639
|
)
|
||||
Interest income
(1)
|
1,332
|
|
|
1,301
|
|
|
4,595
|
|
|
2,901
|
|
||||
Income tax (expense) benefit
|
36,748
|
|
|
39,270
|
|
|
(61,342
|
)
|
|
65,825
|
|
||||
Exploration
(2) (3)
|
(11,490
|
)
|
|
(12,624
|
)
|
|
(36,768
|
)
|
|
(35,021
|
)
|
||||
Amortization of debt discount and deferred financing costs
|
3,792
|
|
|
3,799
|
|
|
11,542
|
|
|
12,478
|
|
||||
Deferred income taxes
|
(36,833
|
)
|
|
(36,668
|
)
|
|
60,672
|
|
|
(67,458
|
)
|
||||
Other, net
(3)
|
151
|
|
|
1,175
|
|
|
(2,160
|
)
|
|
(3,002
|
)
|
||||
Net change in working capital
|
17,997
|
|
|
11,971
|
|
|
(3,725
|
)
|
|
40,153
|
|
||||
Net cash provided by operating activities (GAAP)
(3)
|
$
|
229,659
|
|
|
$
|
128,482
|
|
|
$
|
541,177
|
|
|
$
|
370,610
|
|
(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.
|
PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
|
|||||||||
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)
|
|||||
07/01/18 - 07/31/18
|
115,429
|
|
$
|
25.69
|
|
—
|
|
3,072,184
|
|
08/01/18 - 08/31/18
|
—
|
|
$
|
—
|
|
—
|
|
3,072,184
|
|
09/01/18 - 09/30/18
|
—
|
|
$
|
—
|
|
—
|
|
3,072,184
|
|
Total:
|
115,429
|
|
$
|
25.69
|
|
—
|
|
3,072,184
|
|
(1)
|
All shares purchased by us in the
third
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
|
||
|
|
|
|
November 2, 2018
|
By:
|
/s/ JAVAN D. OTTOSON
|
|
|
|
Javan D. Ottoson
|
|
|
|
President and Chief Executive Officer
|
|
|
|
(Principal Executive Officer)
|
|
|
|
|
|
November 2, 2018
|
By:
|
/s/ A. WADE PURSELL
|
|
|
|
A. Wade Pursell
|
|
|
|
Executive Vice President and Chief Financial Officer
|
|
|
|
(Principal Financial and Accounting Officer)
|
1 Year SM Energy Chart |
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