Delaware
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41-0518430
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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1775 Sherman Street, Suite 1200,
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Denver,
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Colorado
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80203
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(Address of principal executive offices)
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(Zip Code)
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Title of each class
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Trading Symbol(s)
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Name of each exchange on which registered
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Common stock, $.01 par value
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SM
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New York Stock Exchange
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TABLE OF CONTENTS
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Item
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TABLE OF CONTENTS
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(Continued)
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Item
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Page
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•
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the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
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•
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any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”);
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•
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our outlook on future crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this document) prices, well costs, service costs, lease operating costs, and general and administrative costs;
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•
|
the drilling of wells and other exploration and development activities, the ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;
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•
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possible or expected acquisitions and divestitures, including the possible divestiture or farm-down of, or joint venture relating to, certain properties;
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•
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oil, gas, and NGL reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;
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•
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future oil, gas, and NGL production estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;
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•
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cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;
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•
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business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;
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•
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plans, objectives, expectations and intentions; and
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•
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other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report.
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Midland Basin
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South Texas
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Total (1)
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||||||
Proved reserves
|
|
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|
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|
||||||
Oil (MMBbl)
|
167.5
|
|
|
16.6
|
|
|
184.1
|
|
|||
Gas (Bcf)
|
398.8
|
|
|
824.4
|
|
|
1,223.2
|
|
|||
NGLs (MMBbl)
|
0.1
|
|
|
73.9
|
|
|
74.0
|
|
|||
MMBOE (1)
|
234.1
|
|
|
227.8
|
|
|
462.0
|
|
|||
Relative percentage
|
51
|
%
|
|
49
|
%
|
|
100
|
%
|
|||
Proved developed %
|
49
|
%
|
|
58
|
%
|
|
53
|
%
|
|||
Production
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
20.5
|
|
|
1.3
|
|
|
21.9
|
|
|||
Gas (Bcf)
|
34.4
|
|
|
75.4
|
|
|
109.8
|
|
|||
NGLs (MMBbl)
|
—
|
|
|
8.1
|
|
|
8.1
|
|
|||
MMBOE (1)
|
26.3
|
|
|
22.0
|
|
|
48.3
|
|
|||
Avg. daily equivalents (MBOE/d) (1)
|
72.0
|
|
|
60.3
|
|
|
132.3
|
|
|||
Relative percentage
|
54
|
%
|
|
46
|
%
|
|
100
|
%
|
|||
Costs incurred (in millions) (2) (3)
|
$
|
859.6
|
|
|
$
|
160.9
|
|
|
$
|
1,040.2
|
|
(1)
|
Amounts may not calculate due to rounding.
|
(2)
|
Regional costs incurred do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activities that are excluded from this regional table. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
|
(3)
|
Costs incurred for 2019 included $11.3 million related to acquisitions of primarily unproved oil and gas properties in the Midland Basin. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
|
|
As of December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Reserve data:
|
|
|
|
|
|
||||||
Proved developed
|
|
|
|
|
|
||||||
Oil (MMBbl)
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85.0
|
|
|
68.2
|
|
|
58.6
|
|
|||
Gas (Bcf)
|
712.1
|
|
|
699.1
|
|
|
642.9
|
|
|||
NGLs (MMBbl)
|
43.4
|
|
|
60.1
|
|
|
49.0
|
|
|||
MMBOE (1)
|
247.0
|
|
|
244.8
|
|
|
214.7
|
|
|||
Proved undeveloped
|
|
|
|
|
|
||||||
Oil (MMBbl)
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99.1
|
|
|
107.6
|
|
|
99.6
|
|
|||
Gas (Bcf)
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511.1
|
|
|
622.7
|
|
|
637.2
|
|
|||
NGLs (MMBbl)
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30.6
|
|
|
47.2
|
|
|
47.6
|
|
|||
MMBOE (1)
|
214.9
|
|
|
258.6
|
|
|
253.4
|
|
|||
Total proved (1)
|
|
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|
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|
||||||
Oil (MMBbl)
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184.1
|
|
|
175.7
|
|
|
158.2
|
|
|||
Gas (Bcf) (2)
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1,223.2
|
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1,321.8
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1,280.1
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|||
NGLs (MMBbl)
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74.0
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107.4
|
|
|
96.5
|
|
|||
MMBOE
|
462.0
|
|
|
503.4
|
|
|
468.1
|
|
|||
Proved developed reserves %
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53
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%
|
|
49
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%
|
|
46
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%
|
|||
Proved undeveloped reserves %
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47
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%
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|
51
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%
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54
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%
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|||
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|
||||||
Reserve data (in millions):
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|
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|
|
|
||||||
Standardized measure of discounted future net cash flows (GAAP)
|
$
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4,104.0
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$
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4,654.4
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$
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3,024.1
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|
PV-10 (non-GAAP):
|
|
|
|
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|
||||||
Proved developed PV-10
|
$
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2,830.4
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$
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3,084.2
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$
|
1,984.2
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|
Proved undeveloped PV-10
|
1,532.4
|
|
|
2,020.1
|
|
|
1,072.3
|
|
|||
Total proved PV-10 (non-GAAP)
|
$
|
4,362.8
|
|
|
$
|
5,104.3
|
|
|
$
|
3,056.5
|
|
|
|
|
|
|
|
||||||
12-month trailing average prices (3)
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
55.69
|
|
|
$
|
65.56
|
|
|
$
|
51.34
|
|
Gas (per MMBtu)
|
$
|
2.58
|
|
|
$
|
3.10
|
|
|
$
|
3.00
|
|
NGLs (per Bbl)
|
$
|
22.68
|
|
|
$
|
33.45
|
|
|
$
|
27.69
|
|
|
|
|
|
|
|
||||||
Reserve life index (years)
|
9.6
|
|
|
11.5
|
|
|
10.5
|
|
(1)
|
Amounts may not calculate due to rounding.
|
(2)
|
For the years ended December 31, 2019, 2018, and 2017, proved gas reserves contained 44.9 Bcf, 59.1 Bcf, and 48.1 Bcf of gas, respectively, that we expect to produce and use as a field equipment fuel source (primarily to power compressors).
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(3)
|
The prices used in the calculation of proved reserve estimates reflect the 12-month average of the first-day-of-the-month prices in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves.
|
|
As of December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Standardized measure of discounted future net cash flows (GAAP)
|
$
|
4,104.0
|
|
|
$
|
4,654.4
|
|
|
$
|
3,024.1
|
|
Add: 10 percent annual discount, net of income taxes
|
2,955.3
|
|
|
3,847.1
|
|
|
2,573.2
|
|
|||
Add: future undiscounted income taxes
|
579.8
|
|
|
1,012.2
|
|
|
205.7
|
|
|||
Pre-tax undiscounted future net cash flows
|
7,639.1
|
|
|
9,513.7
|
|
|
5,803.0
|
|
|||
Less: 10 percent annual discount without tax effect
|
(3,276.3
|
)
|
|
(4,409.4
|
)
|
|
(2,746.5
|
)
|
|||
PV-10 (non-GAAP)
|
$
|
4,362.8
|
|
|
$
|
5,104.3
|
|
|
$
|
3,056.5
|
|
|
Total
(MMBOE)
|
|
Total proved undeveloped reserves:
|
|
|
Beginning of year
|
258.6
|
|
Revisions of previous estimates
|
(47.6
|
)
|
Additions from discoveries, extensions, and infill
|
78.5
|
|
Purchases of minerals in place
|
1.9
|
|
Removed for five-year rule
|
(9.8
|
)
|
Conversions to proved developed
|
(66.7
|
)
|
End of year
|
214.9
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Net production volumes
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
21.9
|
|
|
18.8
|
|
|
13.7
|
|
|||
Gas (Bcf)
|
109.8
|
|
|
103.2
|
|
|
123.0
|
|
|||
NGLs (MMBbl)
|
8.1
|
|
|
7.9
|
|
|
10.3
|
|
|||
Equivalent (MMBOE) (1)
|
48.3
|
|
|
43.9
|
|
|
44.5
|
|
|||
Midland Basin net production volumes (2)
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
20.5
|
|
|
16.6
|
|
|
8.5
|
|
|||
Gas (Bcf)
|
34.4
|
|
|
25.8
|
|
|
14.7
|
|
|||
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Equivalent (MMBOE) (1)
|
26.3
|
|
|
20.9
|
|
|
11.0
|
|
|||
Eagle Ford shale net production volumes (2)(3)
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
1.3
|
|
|
1.2
|
|
|
1.9
|
|
|||
Gas (Bcf)
|
75.4
|
|
|
76.1
|
|
|
104.0
|
|
|||
NGLs (MMBbl)
|
8.1
|
|
|
7.9
|
|
|
10.1
|
|
|||
Equivalent (MMBOE) (1)
|
21.9
|
|
|
21.8
|
|
|
29.3
|
|
|||
Realized price, before the effect of derivative settlements
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
54.10
|
|
|
$
|
56.80
|
|
|
$
|
47.88
|
|
Gas (per Mcf)
|
$
|
2.39
|
|
|
$
|
3.43
|
|
|
$
|
3.00
|
|
NGLs (per Bbl)
|
$
|
17.26
|
|
|
$
|
27.22
|
|
|
$
|
22.35
|
|
Per BOE
|
$
|
32.84
|
|
|
$
|
37.27
|
|
|
$
|
28.20
|
|
Production expense per BOE
|
|
|
|
|
|
||||||
Lease operating expense
|
$
|
4.67
|
|
|
$
|
4.74
|
|
|
$
|
4.43
|
|
Transportation costs
|
$
|
3.88
|
|
|
$
|
4.36
|
|
|
$
|
5.48
|
|
Production taxes
|
$
|
1.35
|
|
|
$
|
1.52
|
|
|
$
|
1.18
|
|
Ad valorem tax expense
|
$
|
0.48
|
|
|
$
|
0.48
|
|
|
$
|
0.34
|
|
(1)
|
Amounts may not calculate due to rounding.
|
(2)
|
For each of the years ended December 31, 2019, 2018, and 2017, total estimated proved reserves attributed to our Midland Basin assets and our Eagle Ford shale assets exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis.
|
(3)
|
During the first quarter of 2017, we completed the divestiture of our outside-operated Eagle Ford shale assets. These assets represented approximately 1.5 MMBOE of net production on an equivalent basis for the year ended December 31, 2017.
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Development wells
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil
|
119
|
|
|
107
|
|
|
103
|
|
|
92
|
|
|
56
|
|
|
46
|
|
Gas
|
27
|
|
|
16
|
|
|
39
|
|
|
24
|
|
|
38
|
|
|
35
|
|
Non-productive
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
3
|
|
|
147
|
|
|
124
|
|
|
142
|
|
|
116
|
|
|
98
|
|
|
84
|
|
Exploratory wells
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil
|
4
|
|
|
4
|
|
|
18
|
|
|
14
|
|
|
32
|
|
|
29
|
|
Gas
|
4
|
|
|
4
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
Non-productive
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
9
|
|
|
9
|
|
|
19
|
|
|
15
|
|
|
33
|
|
|
29
|
|
Total
|
156
|
|
|
133
|
|
|
161
|
|
|
131
|
|
|
131
|
|
|
113
|
|
|
Developed Acres (1)
|
|
Undeveloped Acres (2)(3)
|
|
Total
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Midland Basin:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
RockStar
|
67,113
|
|
|
59,589
|
|
|
4,966
|
|
|
4,217
|
|
|
72,079
|
|
|
63,806
|
|
Sweetie Peck
|
17,007
|
|
|
15,782
|
|
|
2,835
|
|
|
251
|
|
|
19,842
|
|
|
16,033
|
|
Midland Basin Total (4)
|
84,120
|
|
|
75,371
|
|
|
7,801
|
|
|
4,468
|
|
|
91,921
|
|
|
79,839
|
|
Eagle Ford shale
|
74,247
|
|
|
71,296
|
|
|
88,058
|
|
|
87,631
|
|
|
162,305
|
|
|
158,927
|
|
Other (5)
|
16,259
|
|
|
11,363
|
|
|
90,415
|
|
|
25,599
|
|
|
106,674
|
|
|
36,962
|
|
Total
|
174,626
|
|
|
158,030
|
|
|
186,274
|
|
|
117,698
|
|
|
360,900
|
|
|
275,728
|
|
(1)
|
Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as developed acreage in the table above.
|
(2)
|
Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.
|
(3)
|
As of February 6, 2020, approximately 1,354, 184, and 155 net acres of undeveloped acreage are scheduled to expire by December 31, 2020, 2021, and 2022, respectively, if production is not established or we take no other action to extend the terms of the applicable leases. Certain of our Eagle Ford shale acreage is subject to lease consolidation agreements containing drilling, completion, and other obligations that we currently intend to satisfy. Failure to meet these obligations results in termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous development obligations required by individual leases are not met.
|
(4)
|
As of December 31, 2019, total Midland Basin acreage excludes approximately 1,940 net acres associated with drill-to-earn opportunities that we intend to pursue.
|
(5)
|
Includes other non-core acreage located in Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming.
|
|
For the Years Ended December 31,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
Major customer #1 (1)
|
18
|
%
|
|
18
|
%
|
|
6
|
%
|
Major customer #2 (1)
|
14
|
%
|
|
5
|
%
|
|
1
|
%
|
Major customer #3 (1)
|
13
|
%
|
|
7
|
%
|
|
—
|
%
|
Major customer #4 (1)
|
9
|
%
|
|
10
|
%
|
|
10
|
%
|
Group #1 of entities under common control (2)
|
13
|
%
|
|
18
|
%
|
|
17
|
%
|
Group #2 of entities under common control (2)
|
11
|
%
|
|
12
|
%
|
|
8
|
%
|
(1)
|
These major customers are purchasers of a portion of our production from our Midland Basin assets.
|
(2)
|
In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of our total oil, gas, and NGL production revenue.
|
|
|
Approximate Square Footage Leased
|
|
Corporate
|
|
107,000
|
|
Midland Basin
|
|
59,000
|
|
South Texas
|
|
62,000
|
|
Total
|
|
228,000
|
|
•
|
require the acquisition of various permits before drilling commences;
|
•
|
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;
|
•
|
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and
|
•
|
require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.
|
•
|
global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;
|
•
|
the level of consumer demand for oil, gas, and NGLs;
|
•
|
overall global and domestic economic conditions;
|
•
|
weather conditions;
|
•
|
the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas;
|
•
|
liquefied natural gas deliveries to and from the United States;
|
•
|
the price and availability of alternative fuels;
|
•
|
technological advances and regulations affecting energy consumption and conservation;
|
•
|
the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to maintain effective oil price and production controls;
|
•
|
political instability or armed conflict in oil or gas producing regions;
|
•
|
actual or perceived epidemic risks, such as the Coronavirus outbreak in early 2020;
|
•
|
strengthening and weakening of the United States dollar relative to other currencies;
|
•
|
stockholder activism or activities by non-governmental organizations to limit sources of funding or restrict the exploration and production of oil, gas, and NGLs and related infrastructure; and
|
•
|
governmental regulations and taxes.
|
•
|
the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;
|
•
|
the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;
|
•
|
our ability or the ability of our suppliers or contractors to access the capital markets may be restricted or non-existent at a time when we or they would like, or need, to raise capital for our or their business, including for the exploration and/or development of reserves;
|
•
|
our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and
|
•
|
variable interest rate spread levels, including for LIBOR (or any applicable replacement rate) and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our Credit Agreement.
|
•
|
limit our ability to access debt markets, including for the purpose of refinancing our existing debt;
|
•
|
cause us to refinance or issue debt with less favorable terms and conditions, which debt may restrict, among other things, our ability to make any dividend distributions or repurchase shares;
|
•
|
negatively impact current and prospective customers’ willingness to transact business with us;
|
•
|
impose additional insurance, guarantee and collateral requirements;
|
•
|
limit our access to bank and third-party guarantees, surety bonds and letters of credit; and
|
•
|
cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding indebtedness.
|
•
|
amount and timing of actual production;
|
•
|
supply and demand for oil, gas, and NGLs;
|
•
|
curtailments or increases in consumption by oil purchasers and gas pipelines;
|
•
|
changes in government regulations or taxes, including severance and excise taxes; and
|
•
|
escalations or reductions in service provider and equipment costs resulting from changes in supply and demand.
|
•
|
unexpected adverse drilling or completion conditions;
|
•
|
title problems;
|
•
|
disputes with owners or holders of surface interests on or near areas where we operate;
|
•
|
pressure or geologic irregularities in formations;
|
•
|
engineering and construction delays;
|
•
|
equipment failures or accidents;
|
•
|
hurricanes, tornadoes, flooding, or other adverse weather conditions;
|
•
|
governmental permitting delays;
|
•
|
compliance with environmental and other governmental requirements; and
|
•
|
shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.
|
•
|
our production is less than expected;
|
•
|
one or more counterparties to our commodity derivative contracts default on their contractual obligations; or
|
•
|
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.
|
•
|
$476.8 million of long-term senior unsecured debt relating to our 6.125% Senior Notes due 2022 (“2022 Senior Notes”) that we issued on November 17, 2014;
|
•
|
$500.0 million of long-term senior unsecured debt relating to our 5.0% Senior Notes due 2024 (“2024 Senior Notes”) that we issued on May 20, 2013;
|
•
|
$500.0 million of long-term senior unsecured debt relating to our 5.625% Senior Notes due 2025 (“2025 Senior Notes”) that we issued on May 21, 2015;
|
•
|
$500.0 million of long-term senior unsecured debt relating to our 6.75% Senior Notes due 2026 (“2026 Senior Notes”) that we issued on September 12, 2016;
|
•
|
$500.0 million of long-term senior unsecured debt relating to our 6.625% Senior Notes due 2027 (“2027 Senior Notes”, and all senior notes collectively referred to as the “Senior Notes”) that we issued on August 20, 2018; and,
|
•
|
$172.5 million in aggregate principal amount of long-term senior unsecured convertible debt relating to our 1.50% Senior Convertible Notes due July 1, 2021 (“Senior Convertible Notes”) that we issued on August 12, 2016.
|
•
|
making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;
|
•
|
requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments;
|
•
|
limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;
|
•
|
placing us at a competitive disadvantage compared to our competitors with less debt; and
|
•
|
making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.
|
•
|
incur additional debt;
|
•
|
make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire common stock;
|
•
|
sell assets, including common stock of our subsidiaries;
|
•
|
restrict dividends or other payments of our subsidiaries;
|
•
|
create liens that secure debt;
|
•
|
enter into transactions with affiliates; and
|
•
|
merge or consolidate with, or transfer or lease all or substantially all of our assets to another company.
|
•
|
requirements for methane emission reductions from existing oil and gas equipment;
|
•
|
increased scrutiny for sources emitting high levels of methane, including during permitting processes;
|
•
|
analysis, regulation and reduction of methane emissions as a requirement for project approval; and
|
•
|
actions taken by one agency for a specific industry establishing precedents for other agencies and industry sectors.
|
•
|
changes in oil, gas, or NGL prices;
|
•
|
changes in the outlook for regional, national, or global commodity supply and demand;
|
•
|
variations in drilling, recompletion, and operating activity;
|
•
|
changes in financial estimates by securities analysts;
|
•
|
changes in market valuations of comparable companies;
|
•
|
additions or departures of key personnel;
|
•
|
increased volatility due to the impacts of algorithmic trading practices;
|
•
|
future sales of our common stock;
|
•
|
changes in the national and global economic outlook, including potential impacts from trade agreements; and
|
•
|
international trade relationships, potentially including the effects of trade restrictions or tariffs affecting the raw materials we utilize and the commodities we produce in our business.
|
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)
|
|||||
01/01/2019 -
03/31/2019
|
|
990
|
|
|
$
|
17.82
|
|
|
—
|
|
|
3,072,184
|
|
04/01/2019 -
06/30/2019
|
|
154
|
|
|
$
|
14.91
|
|
|
—
|
|
|
3,072,184
|
|
07/01/2019 -
09/30/2019
|
|
130,992
|
|
|
$
|
12.52
|
|
|
—
|
|
|
3,072,184
|
|
10/01/2019 -
12/31/2019
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
Total
|
|
132,136
|
|
|
$
|
12.56
|
|
|
—
|
|
|
3,072,184
|
|
(1)
|
All shares purchased by us in 2019 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying Restricted Stock Units (“RSUs”) issued under the terms of award agreements granted under the SM Energy Equity Incentive Compensation Plan, as amended and restated effective as of May 22, 2018 (the “Equity 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.
|
|
As of or for the Years Ended December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
|
(in millions, except per share data)
|
||||||||||||||||||
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total operating revenues and other income
|
$
|
1,590.1
|
|
|
$
|
2,067.1
|
|
|
$
|
1,129.4
|
|
|
$
|
1,217.5
|
|
|
$
|
1,557.0
|
|
Net income (loss)
|
$
|
(187.0
|
)
|
|
$
|
508.4
|
|
|
$
|
(160.8
|
)
|
|
$
|
(757.7
|
)
|
|
$
|
(447.7
|
)
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
(1.66
|
)
|
|
$
|
4.54
|
|
|
$
|
(1.44
|
)
|
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
Diluted
|
$
|
(1.66
|
)
|
|
$
|
4.48
|
|
|
$
|
(1.44
|
)
|
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
Cash dividends declared and paid per common share
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|||||||||||
Total assets
|
$
|
6,292.2
|
|
|
$
|
6,352.9
|
|
|
$
|
6,176.8
|
|
|
$
|
6,393.5
|
|
|
$
|
5,621.6
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revolving credit facility
|
$
|
122.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
202.0
|
|
Senior Notes, net of unamortized deferred financing costs
|
$
|
2,453.0
|
|
|
$
|
2,448.4
|
|
|
$
|
2,769.7
|
|
|
$
|
2,766.7
|
|
|
$
|
2,316.0
|
|
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
$
|
157.3
|
|
|
$
|
147.9
|
|
|
$
|
139.1
|
|
|
$
|
130.9
|
|
|
$
|
—
|
|
Supplemental Selected Financial and Operations Data
|
|||||||||||||||||||
|
|
||||||||||||||||||
|
As of or for the Years Ended December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
Balance sheet data (in millions):
|
|
|
|
|
|
|
|
|
|||||||||||
Total working capital (deficit)
|
$
|
(219.4
|
)
|
|
$
|
(36.8
|
)
|
|
$
|
(10.1
|
)
|
|
$
|
(190.5
|
)
|
|
$
|
216.5
|
|
Total stockholders’ equity
|
$
|
2,749.0
|
|
|
$
|
2,920.3
|
|
|
$
|
2,394.6
|
|
|
$
|
2,497.1
|
|
|
$
|
1,852.4
|
|
Weighted-average common shares outstanding (in thousands):
|
|
|
|
|
|
|
|||||||||||||
Basic
|
112,544
|
|
|
111,912
|
|
|
111,428
|
|
|
76,568
|
|
|
67,723
|
|
|||||
Diluted
|
112,544
|
|
|
113,502
|
|
|
111,428
|
|
|
76,568
|
|
|
67,723
|
|
|||||
Reserves:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
184.1
|
|
|
175.7
|
|
|
158.2
|
|
|
104.9
|
|
|
145.3
|
|
|||||
Gas (Bcf)
|
1,223.2
|
|
|
1,321.8
|
|
|
1,280.1
|
|
|
1,111.1
|
|
|
1,264.0
|
|
|||||
NGLs (MMBbl)
|
74.0
|
|
|
107.4
|
|
|
96.5
|
|
|
105.7
|
|
|
115.4
|
|
|||||
MMBOE (1)
|
462.0
|
|
|
503.4
|
|
|
468.1
|
|
|
395.8
|
|
|
471.3
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Production and operations (in millions):
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil, gas, and NGL production revenue
|
$
|
1,585.8
|
|
|
$
|
1,636.4
|
|
|
$
|
1,253.8
|
|
|
$
|
1,178.4
|
|
|
$
|
1,499.9
|
|
Oil, gas, and NGL production expense
|
$
|
500.7
|
|
|
$
|
487.4
|
|
|
$
|
507.9
|
|
|
$
|
597.6
|
|
|
$
|
723.6
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
823.8
|
|
|
$
|
665.3
|
|
|
$
|
557.0
|
|
|
$
|
790.7
|
|
|
$
|
921.0
|
|
General and administrative (2)
|
$
|
132.8
|
|
|
$
|
116.5
|
|
|
$
|
117.3
|
|
|
$
|
124.8
|
|
|
$
|
156.1
|
|
Production volumes:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
21.9
|
|
|
18.8
|
|
|
13.7
|
|
|
16.6
|
|
|
19.2
|
|
|||||
Gas (Bcf)
|
109.8
|
|
|
103.2
|
|
|
123.0
|
|
|
146.9
|
|
|
173.6
|
|
|||||
NGLs (MMBbl)
|
8.1
|
|
|
7.9
|
|
|
10.3
|
|
|
14.2
|
|
|
16.1
|
|
|||||
MMBOE (1)
|
48.3
|
|
|
43.9
|
|
|
44.5
|
|
|
55.3
|
|
|
64.2
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Realized price, before the effect of derivative settlements:
|
|
|
|
|
|
|
|||||||||||||
Oil (per Bbl)
|
$
|
54.10
|
|
|
$
|
56.80
|
|
|
$
|
47.88
|
|
|
$
|
36.85
|
|
|
$
|
41.49
|
|
Gas (per Mcf)
|
$
|
2.39
|
|
|
$
|
3.43
|
|
|
$
|
3.00
|
|
|
$
|
2.30
|
|
|
$
|
2.57
|
|
NGLs (per Bbl)
|
$
|
17.26
|
|
|
$
|
27.22
|
|
|
$
|
22.35
|
|
|
$
|
16.16
|
|
|
$
|
15.92
|
|
Per BOE
|
$
|
32.84
|
|
|
$
|
37.27
|
|
|
$
|
28.20
|
|
|
$
|
21.32
|
|
|
$
|
23.36
|
|
Expense per BOE:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expense
|
$
|
4.67
|
|
|
$
|
4.74
|
|
|
$
|
4.43
|
|
|
$
|
3.51
|
|
|
$
|
3.73
|
|
Transportation costs
|
$
|
3.88
|
|
|
$
|
4.36
|
|
|
$
|
5.48
|
|
|
$
|
6.16
|
|
|
$
|
6.02
|
|
Production taxes
|
$
|
1.35
|
|
|
$
|
1.52
|
|
|
$
|
1.18
|
|
|
$
|
0.94
|
|
|
$
|
1.13
|
|
Ad valorem tax expense
|
$
|
0.48
|
|
|
$
|
0.48
|
|
|
$
|
0.34
|
|
|
$
|
0.21
|
|
|
$
|
0.39
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
17.06
|
|
|
$
|
15.15
|
|
|
$
|
12.53
|
|
|
$
|
14.30
|
|
|
$
|
14.34
|
|
General and administrative (2)
|
$
|
2.75
|
|
|
$
|
2.65
|
|
|
$
|
2.64
|
|
|
$
|
2.26
|
|
|
$
|
2.43
|
|
Statement of cash flows data (in millions):
|
|
|
|
|
|
|
|
|
|
||||||||||
Provided by operating activities (2)
|
$
|
823.6
|
|
|
$
|
720.6
|
|
|
$
|
515.4
|
|
|
$
|
552.8
|
|
|
$
|
990.8
|
|
Used in investing activities (2)
|
$
|
(1,013.3
|
)
|
|
$
|
(587.9
|
)
|
|
$
|
(201.5
|
)
|
|
$
|
(1,867.6
|
)
|
|
$
|
(1,144.6
|
)
|
Provided by (used in) financing activities (2)
|
$
|
111.8
|
|
|
$
|
(368.7
|
)
|
|
$
|
(12.3
|
)
|
|
$
|
1,327.2
|
|
|
$
|
153.7
|
|
(1)
|
Amounts may not calculate due to rounding.
|
(2)
|
As a result of adopting new accounting standards in prior periods, certain prior period amounts have been reclassified to conform to the current period presentation on the consolidated financial statements.
|
•
|
net loss of $187.0 million, or $1.66 per diluted share, for the year ended December 31, 2019, compared with net income of $508.4 million, or $4.48 per diluted share, for the year ended December 31, 2018. Please refer to Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion regarding the components of net income (loss) for each period presented;
|
•
|
net cash provided by operating activities was $823.6 million for the year ended December 31, 2019, compared with $720.6 million in 2018, which was an increase of 14 percent year-over-year. Please refer to Analysis of Cash Flow Changes Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion; and
|
•
|
adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2019, was $993.4 million, compared with $900.4 million for the same period in 2018. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to our net income (loss) and net cash provided by operating activities.
|
|
Midland Basin
|
|
South Texas
|
|
Total
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wells drilled but not completed at December 31, 2018
|
61
|
|
|
55
|
|
|
29
|
|
|
23
|
|
|
90
|
|
|
78
|
|
Wells drilled
|
113
|
|
|
104
|
|
|
25
|
|
|
20
|
|
|
138
|
|
|
124
|
|
Wells completed
|
(123
|
)
|
|
(111
|
)
|
|
(31
|
)
|
|
(20
|
)
|
|
(154
|
)
|
|
(131
|
)
|
Other (1)
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
(2
|
)
|
Wells drilled but not completed at December 31, 2019
|
51
|
|
|
48
|
|
|
21
|
|
|
21
|
|
|
72
|
|
|
69
|
|
(1)
|
Includes adjustments related to previously drilled wells that we no longer intend to complete.
|
|
For the Year Ended
|
||
|
December 31, 2019
|
||
|
(in millions)
|
||
Development costs
|
$
|
914.0
|
|
Exploration costs
|
115.0
|
|
|
Acquisitions
|
|
||
Proved properties
|
(0.3
|
)
|
|
Unproved properties
|
11.6
|
|
|
Total, including asset retirement obligations (1)
|
$
|
1,040.2
|
|
(1)
|
Please refer to the caption Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
|
|
Midland Basin
|
|
South Texas
|
|
Total
|
|||
Production:
|
|
|
|
|
|
|||
Oil (MMBbl)
|
20.5
|
|
|
1.3
|
|
|
21.9
|
|
Gas (Bcf)
|
34.4
|
|
|
75.4
|
|
|
109.8
|
|
NGLs (MMBbl)
|
—
|
|
|
8.1
|
|
|
8.1
|
|
Equivalent (MMBOE)
|
26.3
|
|
|
22.0
|
|
|
48.3
|
|
Avg. daily equivalents (MBOE/d)
|
72.0
|
|
|
60.3
|
|
|
132.3
|
|
Relative percentage
|
54
|
%
|
|
46
|
%
|
|
100
|
%
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Oil (per Bbl):
|
|
|
|
|
|
||||||
Average NYMEX contract monthly price
|
$
|
57.03
|
|
|
$
|
64.77
|
|
|
$
|
50.95
|
|
Realized price, before the effect of derivative settlements
|
$
|
54.10
|
|
|
$
|
56.80
|
|
|
$
|
47.88
|
|
Effect of oil derivative settlements
|
$
|
(0.90
|
)
|
|
$
|
(3.67
|
)
|
|
$
|
(2.28
|
)
|
|
|
|
|
|
|
||||||
Gas:
|
|
|
|
|
|
||||||
Average NYMEX monthly settle price (per MMBtu)
|
$
|
2.63
|
|
|
$
|
3.09
|
|
|
$
|
3.11
|
|
Realized price, before the effect of derivative settlements (per Mcf)
|
$
|
2.39
|
|
|
$
|
3.43
|
|
|
$
|
3.00
|
|
Effect of gas derivative settlements (per Mcf)
|
$
|
0.21
|
|
|
$
|
(0.12
|
)
|
|
$
|
0.72
|
|
|
|
|
|
|
|
||||||
NGLs (per Bbl):
|
|
|
|
|
|
||||||
Average OPIS price (1)
|
$
|
22.34
|
|
|
$
|
32.96
|
|
|
$
|
27.63
|
|
Realized price, before the effect of derivative settlements
|
$
|
17.26
|
|
|
$
|
27.22
|
|
|
$
|
22.35
|
|
Effect of NGL derivative settlements
|
$
|
4.43
|
|
|
$
|
(6.78
|
)
|
|
$
|
(3.44
|
)
|
(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 February 6, 2020
|
|
As of December 31, 2019
|
||||
NYMEX WTI oil (per Bbl)
|
$
|
51.46
|
|
|
$
|
59.01
|
|
NYMEX Henry Hub gas (per MMBtu)
|
$
|
2.15
|
|
|
$
|
2.28
|
|
OPIS NGLs (per Bbl)
|
$
|
18.09
|
|
|
$
|
20.00
|
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2019
|
|
2019
|
|
2019
|
|
2019
|
||||||||
|
(in millions)
|
||||||||||||||
Production (MMBOE)
|
12.8
|
|
|
12.4
|
|
|
12.4
|
|
|
10.7
|
|
||||
Oil, gas, and NGL production revenue
|
$
|
449.0
|
|
|
$
|
389.4
|
|
|
$
|
406.9
|
|
|
$
|
340.5
|
|
Oil, gas, and NGL production expense
|
$
|
127.3
|
|
|
$
|
129.0
|
|
|
$
|
123.1
|
|
|
$
|
121.3
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
228.7
|
|
|
$
|
211.1
|
|
|
$
|
206.3
|
|
|
$
|
177.7
|
|
Exploration
|
$
|
17.7
|
|
|
$
|
11.6
|
|
|
$
|
10.9
|
|
|
$
|
11.3
|
|
General and administrative
|
$
|
37.2
|
|
|
$
|
32.6
|
|
|
$
|
30.9
|
|
|
$
|
32.1
|
|
Net income (loss)
|
$
|
(102.1
|
)
|
|
$
|
42.2
|
|
|
$
|
50.4
|
|
|
$
|
(177.6
|
)
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2019
|
|
2019
|
|
2019
|
|
2019
|
||||||||
Average net daily production equivalent (MBOE per day)
|
138.8
|
|
|
134.9
|
|
|
136.5
|
|
|
118.7
|
|
||||
Lease operating expense (per BOE)
|
$
|
4.67
|
|
|
$
|
4.73
|
|
|
$
|
4.16
|
|
|
$
|
5.20
|
|
Transportation costs (per BOE)
|
$
|
3.46
|
|
|
$
|
4.00
|
|
|
$
|
4.00
|
|
|
$
|
4.08
|
|
Production taxes as a percent of oil, gas, and NGL production revenue
|
4.2
|
%
|
|
4.1
|
%
|
|
4.0
|
%
|
|
4.1
|
%
|
||||
Ad valorem tax expense (per BOE)
|
$
|
0.37
|
|
|
$
|
0.39
|
|
|
$
|
0.44
|
|
|
$
|
0.76
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
|
$
|
17.91
|
|
|
$
|
17.02
|
|
|
$
|
16.61
|
|
|
$
|
16.63
|
|
General and administrative (per BOE)
|
$
|
2.92
|
|
|
$
|
2.63
|
|
|
$
|
2.49
|
|
|
$
|
3.00
|
|
|
For the Years Ended
December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2019/2018
|
|
2018/2017
|
|
2019/2018
|
|
2018/2017
|
||||||||||||||
Net production volumes: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MMBbl)
|
21.9
|
|
|
18.8
|
|
|
13.7
|
|
|
3.1
|
|
|
5.1
|
|
|
17
|
%
|
|
37
|
%
|
|||||||
Gas (Bcf)
|
109.8
|
|
|
103.2
|
|
|
123.0
|
|
|
6.6
|
|
|
(19.8
|
)
|
|
6
|
%
|
|
(16
|
)%
|
|||||||
NGLs (MMBbl)
|
8.1
|
|
|
7.9
|
|
|
10.3
|
|
|
0.2
|
|
|
(2.4
|
)
|
|
2
|
%
|
|
(23
|
)%
|
|||||||
Equivalent (MMBOE)
|
48.3
|
|
|
43.9
|
|
|
44.5
|
|
|
4.4
|
|
|
(0.6
|
)
|
|
10
|
%
|
|
(1
|
)%
|
|||||||
Average net daily production: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MBbl per day)
|
59.9
|
|
|
51.4
|
|
|
37.4
|
|
|
8.5
|
|
|
14.0
|
|
|
17
|
%
|
|
37
|
%
|
|||||||
Gas (MMcf per day)
|
300.8
|
|
|
282.7
|
|
|
337.0
|
|
|
18.1
|
|
|
(54.3
|
)
|
|
6
|
%
|
|
(16
|
)%
|
|||||||
NGLs (MBbl per day)
|
22.2
|
|
|
21.8
|
|
|
28.2
|
|
|
0.5
|
|
|
(6.4
|
)
|
|
2
|
%
|
|
(23
|
)%
|
|||||||
Equivalent (MBOE per day)
|
132.3
|
|
|
120.3
|
|
|
121.8
|
|
|
12.0
|
|
|
(1.5
|
)
|
|
10
|
%
|
|
(1
|
)%
|
|||||||
Oil, gas, and NGL production revenue (in millions): (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Oil production revenue
|
$
|
1,183.2
|
|
|
$
|
1,065.7
|
|
|
$
|
654.3
|
|
|
$
|
117.5
|
|
|
$
|
411.4
|
|
|
11
|
%
|
|
63
|
%
|
||
Gas production revenue
|
262.5
|
|
|
354.5
|
|
|
369.4
|
|
|
(91.9
|
)
|
|
(15.0
|
)
|
|
(26
|
)%
|
|
(4
|
)%
|
|||||||
NGL production revenue
|
140.0
|
|
|
216.2
|
|
|
230.1
|
|
|
(76.2
|
)
|
|
(13.9
|
)
|
|
(35
|
)%
|
|
(6
|
)%
|
|||||||
Total oil, gas, and NGL production revenue
|
$
|
1,585.8
|
|
|
$
|
1,636.4
|
|
|
$
|
1,253.8
|
|
|
$
|
(50.6
|
)
|
|
$
|
382.6
|
|
|
(3
|
)%
|
|
31
|
%
|
||
Oil, gas, and NGL production expense (in millions): (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Lease operating expense
|
$
|
225.5
|
|
|
$
|
208.1
|
|
|
$
|
196.9
|
|
|
$
|
17.4
|
|
|
$
|
11.2
|
|
|
8
|
%
|
|
6
|
%
|
||
Transportation costs
|
187.1
|
|
|
191.5
|
|
|
243.6
|
|
|
(4.4
|
)
|
|
(52.1
|
)
|
|
(2
|
)%
|
|
(21
|
)%
|
|||||||
Production taxes
|
65.0
|
|
|
66.9
|
|
|
52.4
|
|
|
(1.9
|
)
|
|
14.5
|
|
|
(3
|
)%
|
|
28
|
%
|
|||||||
Ad valorem tax expense
|
23.1
|
|
|
20.9
|
|
|
15.0
|
|
|
2.2
|
|
|
5.9
|
|
|
10
|
%
|
|
39
|
%
|
|||||||
Total oil, gas, and NGL production expense
|
$
|
500.7
|
|
|
$
|
487.4
|
|
|
$
|
507.9
|
|
|
$
|
13.3
|
|
|
$
|
(20.5
|
)
|
|
3
|
%
|
|
(4
|
)%
|
||
Realized price, before the effect of derivative settlements:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Oil (per Bbl)
|
$
|
54.10
|
|
|
$
|
56.80
|
|
|
$
|
47.88
|
|
|
$
|
(2.70
|
)
|
|
$
|
8.92
|
|
|
(5
|
)%
|
|
19
|
%
|
||
Gas (per Mcf)
|
$
|
2.39
|
|
|
$
|
3.43
|
|
|
$
|
3.00
|
|
|
$
|
(1.04
|
)
|
|
$
|
0.43
|
|
|
(30
|
)%
|
|
14
|
%
|
||
NGLs (per Bbl)
|
$
|
17.26
|
|
|
$
|
27.22
|
|
|
$
|
22.35
|
|
|
$
|
(9.96
|
)
|
|
$
|
4.87
|
|
|
(37
|
)%
|
|
22
|
%
|
||
Per BOE
|
$
|
32.84
|
|
|
$
|
37.27
|
|
|
$
|
28.20
|
|
|
$
|
(4.43
|
)
|
|
$
|
9.07
|
|
|
(12
|
)%
|
|
32
|
%
|
||
Per BOE data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expense
|
$
|
4.67
|
|
|
$
|
4.74
|
|
|
$
|
4.43
|
|
|
$
|
(0.07
|
)
|
|
$
|
0.31
|
|
|
(1
|
)%
|
|
7
|
%
|
||
Transportation costs
|
$
|
3.88
|
|
|
$
|
4.36
|
|
|
$
|
5.48
|
|
|
$
|
(0.48
|
)
|
|
$
|
(1.12
|
)
|
|
(11
|
)%
|
|
(20
|
)%
|
||
Production taxes
|
$
|
1.35
|
|
|
$
|
1.52
|
|
|
$
|
1.18
|
|
|
$
|
(0.17
|
)
|
|
$
|
0.34
|
|
|
(11
|
)%
|
|
29
|
%
|
||
Ad valorem tax expense
|
$
|
0.48
|
|
|
$
|
0.48
|
|
|
$
|
0.34
|
|
|
$
|
—
|
|
|
$
|
0.14
|
|
|
—
|
%
|
|
41
|
%
|
||
Total production costs (1)
|
$
|
10.38
|
|
|
$
|
11.10
|
|
|
$
|
11.43
|
|
|
$
|
(0.72
|
)
|
|
$
|
(0.33
|
)
|
|
(6
|
)%
|
|
(3
|
)%
|
||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
17.06
|
|
|
$
|
15.15
|
|
|
$
|
12.53
|
|
|
$
|
1.91
|
|
|
$
|
2.62
|
|
|
13
|
%
|
|
21
|
%
|
||
General and administrative
|
$
|
2.75
|
|
|
$
|
2.65
|
|
|
$
|
2.64
|
|
|
$
|
0.10
|
|
|
$
|
0.01
|
|
|
4
|
%
|
|
—
|
%
|
||
Derivative settlement gain (loss) (2)
|
$
|
0.81
|
|
|
$
|
(3.09
|
)
|
|
$
|
0.48
|
|
|
$
|
3.90
|
|
|
$
|
(3.57
|
)
|
|
126
|
%
|
|
(744
|
)%
|
||
Earnings per share information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Basic weighted-average common shares outstanding (in thousands)
|
112,544
|
|
|
111,912
|
|
|
111,428
|
|
|
632
|
|
|
484
|
|
|
1
|
%
|
|
—
|
%
|
|||||||
Diluted weighted-average common shares outstanding (in thousands)
|
112,544
|
|
|
113,502
|
|
|
111,428
|
|
|
(958
|
)
|
|
2,074
|
|
|
(1
|
)%
|
|
2
|
%
|
|||||||
Basic net income (loss) per common share
|
$
|
(1.66
|
)
|
|
$
|
4.54
|
|
|
$
|
(1.44
|
)
|
|
$
|
(6.20
|
)
|
|
$
|
5.98
|
|
|
(137
|
)%
|
|
415
|
%
|
||
Diluted net income (loss) per common share
|
$
|
(1.66
|
)
|
|
$
|
4.48
|
|
|
$
|
(1.44
|
)
|
|
$
|
(6.14
|
)
|
|
$
|
5.92
|
|
|
(137
|
)%
|
|
411
|
%
|
(1)
|
Amounts and percentage changes may not calculate due to rounding.
|
(2)
|
Derivative settlements for the years ended December 31, 2019, 2018, and 2017, are included within the net derivative (gain) loss line item in the accompanying consolidated statements of operations (“accompanying statements of operations”).
|
|
Net Equivalent Production Increase (Decrease)
|
|
Production Revenue Increase (Decrease)
|
|
Production Expense Increase (Decrease)
|
|||||
|
(MBOE per day)
|
|
(in millions)
|
|
(in millions)
|
|||||
Midland Basin
|
14.6
|
|
|
$
|
131.1
|
|
|
$
|
31.5
|
|
South Texas
|
0.4
|
|
|
(124.5
|
)
|
|
5.2
|
|
||
Rocky Mountain (1)
|
(3.1
|
)
|
|
(57.2
|
)
|
|
(23.3
|
)
|
||
Total
|
12.0
|
|
|
$
|
(50.6
|
)
|
|
$
|
13.3
|
|
(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.
|
|
Net Equivalent Production Increase (Decrease)
|
|
Production Revenue Increase (Decrease)
|
|
Production Expense Increase (Decrease)
|
|||||
|
(MBOE per day)
|
|
(in millions)
|
|
(in millions)
|
|||||
Midland Basin
|
27.4
|
|
|
$
|
582.5
|
|
|
$
|
89.5
|
|
South Texas
|
(20.8
|
)
|
|
(95.9
|
)
|
|
(64.5
|
)
|
||
Rocky Mountain (1)
|
(8.1
|
)
|
|
(104.0
|
)
|
|
(45.5
|
)
|
||
Total
|
(1.5
|
)
|
|
$
|
382.6
|
|
|
$
|
(20.5
|
)
|
(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 Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Net gain (loss) on divestiture activity
|
$
|
0.9
|
|
|
$
|
426.9
|
|
|
$
|
(131.0
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
823.8
|
|
|
$
|
665.3
|
|
|
$
|
557.0
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Geological and geophysical expenses
|
$
|
2.9
|
|
|
$
|
5.6
|
|
|
$
|
4.0
|
|
Exploratory dry hole
|
4.8
|
|
|
—
|
|
|
2.4
|
|
|||
Overhead and other expenses
|
43.8
|
|
|
49.6
|
|
|
48.3
|
|
|||
Total
|
$
|
51.5
|
|
|
$
|
55.2
|
|
|
$
|
54.7
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Impairment of proved properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3.8
|
|
Abandonment and impairment of unproved properties
|
33.8
|
|
|
49.9
|
|
|
12.3
|
|
|||
Total
|
$
|
33.8
|
|
|
$
|
49.9
|
|
|
$
|
16.1
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
General and administrative
|
$
|
132.8
|
|
|
$
|
116.5
|
|
|
$
|
117.3
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Net derivative (gain) loss
|
$
|
97.5
|
|
|
$
|
(161.8
|
)
|
|
$
|
26.4
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Interest expense
|
$
|
(159.1
|
)
|
|
$
|
(160.9
|
)
|
|
$
|
(179.3
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Loss on extinguishment of debt
|
$
|
—
|
|
|
$
|
(26.7
|
)
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions, except tax rate)
|
||||||||||
Income tax (expense) benefit
|
$
|
44.0
|
|
|
$
|
(143.4
|
)
|
|
$
|
183.0
|
|
Effective tax rate
|
19.1
|
%
|
|
22.0
|
%
|
|
53.2
|
%
|
|
For the Years Ended December 31,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
Weighted-average interest rate
|
6.4
|
%
|
|
6.4
|
%
|
|
6.4
|
%
|
Weighted-average borrowing rate
|
5.7
|
%
|
|
5.8
|
%
|
|
5.8
|
%
|
|
For the Years Ended December 31,
|
|
Amount Change Between
|
||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2019/2018
|
|
2018/2017
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Net cash provided by operating activities
|
$
|
823.6
|
|
|
$
|
720.6
|
|
|
$
|
515.4
|
|
|
$
|
103.0
|
|
|
$
|
205.2
|
|
|
For the Years Ended December 31,
|
|
Amount Change Between
|
||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2019/2018
|
|
2018/2017
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Net cash used in investing activities
|
$
|
(1,013.3
|
)
|
|
$
|
(587.9
|
)
|
|
$
|
(201.5
|
)
|
|
$
|
(425.4
|
)
|
|
$
|
(386.4
|
)
|
|
For the Years Ended December 31,
|
|
Amount Change Between
|
||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2019/2018
|
|
2018/2017
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Net cash provided by (used in) financing activities
|
$
|
111.8
|
|
|
$
|
(368.7
|
)
|
|
$
|
(12.3
|
)
|
|
$
|
480.5
|
|
|
$
|
(356.4
|
)
|
Contractual Obligations
|
|
Total
|
|
Less than 1 year
|
|
1-3 years
|
|
3-5 years
|
|
More than 5 years
|
||||||||||
Long-term debt (1)
|
|
$
|
2,771.8
|
|
|
$
|
—
|
|
|
$
|
649.3
|
|
|
$
|
622.5
|
|
|
$
|
1,500.0
|
|
Interest payments (2)
|
|
832.7
|
|
|
160.4
|
|
|
313.2
|
|
|
222.4
|
|
|
136.7
|
|
|||||
Delivery commitments (3)
|
|
218.5
|
|
|
46.3
|
|
|
133.7
|
|
|
32.5
|
|
|
6.0
|
|
|||||
Operating leases and contracts (3)
|
|
131.1
|
|
|
56.3
|
|
|
34.6
|
|
|
21.5
|
|
|
18.7
|
|
|||||
Asset retirement obligations (4)
|
|
114.4
|
|
|
3.1
|
|
|
6.2
|
|
|
36.0
|
|
|
69.1
|
|
|||||
Derivative liabilities (5)
|
|
54.6
|
|
|
51.1
|
|
|
3.5
|
|
|
—
|
|
|
—
|
|
|||||
Other (6)
|
|
35.6
|
|
|
5.6
|
|
|
14.9
|
|
|
15.1
|
|
|
—
|
|
|||||
Total
|
|
$
|
4,158.7
|
|
|
$
|
322.8
|
|
|
$
|
1,155.4
|
|
|
$
|
950.0
|
|
|
$
|
1,730.5
|
|
(1)
|
Long-term debt consists of the $122.5 million balance on our revolving credit facility, our Senior Notes, and our Senior Convertible Notes and assumes no principal repayment until the maturity dates of these instruments. The actual payment dates may vary significantly.
|
(2)
|
Interest payments on our Senior Notes and Senior Convertible Notes are estimated assuming no principal repayment until the maturity dates of these instruments. Interest payments on our credit facility have been estimated using the rate applicable to the outstanding balance on our credit facility as of December 31, 2019, and assume no future borrowings or repayments until the September 28, 2023 maturity date of the Credit Agreement. The actual interest payments on our Senior Notes, Senior Convertible Notes, and our credit facility may vary significantly.
|
(3)
|
Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our operating leases, contracts, and gathering, processing, transportation throughput, and delivery commitments. The amount relating to our gathering, processing, transportation throughput, and delivery commitments reflects the aggregate undiscounted deficiency payments assuming we delivered no product. This amount does not include any costs that may be incurred for certain contracts where we cannot predict with accuracy the amount and timing of any payments that may be incurred for not meeting certain minimum commitments, as such payments are dependent upon the price of oil in effect at the time of settlement.
|
(4)
|
Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on our accompanying consolidated balance sheets (“accompanying balance sheets”) as of December 31, 2019. The timing and amount of the ultimate settlement of these obligations is unknown and can be impacted by economic factors, a change in development plans, and federal and state regulations. Please refer to Note 14 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion.
|
(5)
|
Amounts shown represent only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices as of December 31, 2019, and exclude estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts presented on the accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of non-performance for us and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, as they are subject to continuing market risk and commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
|
(6)
|
The majority of this amount is related to the unfunded portion of our estimated pension liability of $35.2 million, for which we have estimated the timing of future payments based on historical annual contribution amounts.
|
|
For the Years Ended December 31,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
|
MMBOE Change
|
|
MMBOE Change
|
|
MMBOE Change
|
|||
Revisions resulting from performance
|
(14.9
|
)
|
|
(59.7
|
)
|
|
7.4
|
|
Removal of proved undeveloped reserves no longer in our five-year development plan
|
(9.8
|
)
|
|
(22.6
|
)
|
|
(13.9
|
)
|
Revisions resulting from price changes
|
(70.0
|
)
|
|
13.5
|
|
|
23.1
|
|
Total
|
(94.7
|
)
|
|
(68.8
|
)
|
|
16.6
|
|
|
For the year ended December 31, 2019
|
||||
|
MMBOE Change
|
|
Percentage Change
|
||
10 percent decrease in SEC pricing (1)
|
(7.2
|
)
|
|
(2
|
)%
|
Average NYMEX strip pricing as of fiscal year end (2)
|
(5.2
|
)
|
|
(1
|
)%
|
10 percent decrease in proved undeveloped reserves (3)
|
(21.5
|
)
|
|
(5
|
)%
|
(1)
|
The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated proved reserve volumes as of December 31, 2019, and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.
|
(2)
|
The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2019. SEC pricing of $55.69 per Bbl for oil, $2.58 per MMBtu for gas, and $22.68 per Bbl for NGLs as of December 31, 2019, compared to the five-year average NYMEX strip pricing of $53.65 per Bbl for oil, $2.42 per MMBtu for gas, and $19.67 per Bbl for NGLs as of December 31, 2019, would result in a one percent decrease to our total reported estimated proved reserve volumes.
|
(3)
|
The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2019, and does not include any additional impacts to our estimated proved reserves.
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Net income (loss) (GAAP)
|
$
|
(187,001
|
)
|
|
$
|
508,407
|
|
|
$
|
(160,843
|
)
|
Interest expense
|
159,102
|
|
|
160,906
|
|
|
179,257
|
|
|||
Income tax expense (benefit)
|
(44,043
|
)
|
|
143,370
|
|
|
(182,970
|
)
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
823,798
|
|
|
665,313
|
|
|
557,036
|
|
|||
Exploration (1)
|
46,995
|
|
|
49,627
|
|
|
48,413
|
|
|||
Impairment of oil and gas properties
|
33,842
|
|
|
49,889
|
|
|
16,078
|
|
|||
Stock-based compensation expense
|
24,318
|
|
|
23,908
|
|
|
22,700
|
|
|||
Net derivative (gain) loss
|
97,539
|
|
|
(161,832
|
)
|
|
26,414
|
|
|||
Derivative settlement gain (loss)
|
39,222
|
|
|
(135,803
|
)
|
|
21,234
|
|
|||
Net (gain) loss on divestiture activity
|
(862
|
)
|
|
(426,917
|
)
|
|
131,028
|
|
|||
Loss on extinguishment of debt
|
—
|
|
|
26,740
|
|
|
35
|
|
|||
Other, net
|
481
|
|
|
(3,214
|
)
|
|
4,852
|
|
|||
Adjusted EBITDAX (non-GAAP)
|
993,391
|
|
|
900,394
|
|
|
663,234
|
|
|||
Interest expense
|
(159,102
|
)
|
|
(160,906
|
)
|
|
(179,257
|
)
|
|||
Income tax (expense) benefit
|
44,043
|
|
|
(143,370
|
)
|
|
182,970
|
|
|||
Exploration (1)
|
(46,995
|
)
|
|
(49,627
|
)
|
|
(48,413
|
)
|
|||
Amortization of debt discount and deferred financing costs
|
15,474
|
|
|
15,258
|
|
|
16,276
|
|
|||
Deferred income taxes
|
(41,835
|
)
|
|
141,708
|
|
|
(192,066
|
)
|
|||
Other, net
|
1,739
|
|
|
3,501
|
|
|
3,033
|
|
|||
Changes in current assets and liabilities
|
16,852
|
|
|
13,671
|
|
|
69,613
|
|
|||
Net cash provided by operating activities (GAAP)
|
$
|
823,567
|
|
|
$
|
720,629
|
|
|
$
|
515,390
|
|
(1)
|
Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items 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.
|
Description of the Matter
|
At December 31, 2019, the net book value of the Company’s proved oil and gas properties was $4.8 billion, and depletion, depreciation and amortization (DD&A) expense was $823.8 million for the year then ended. As described in Note 1 to the consolidated financial statements, under the successful efforts method of accounting, the costs of development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field are depleted as a group of assets using the units-of-production method based on proved developed oil and gas reserves, as estimated by the Company’s engineering technical team. Similarly, proved leasehold costs are depleted on the same group asset basis; however, the units-of-production method is based on total proved oil and gas reserves, as estimated by the Company’s engineering technical team. Significant judgment is required by the Company’s engineering technical team in evaluating geoscience and engineering data when estimating proved oil and gas reserves. Estimating reserves also requires the use of inputs, including oil and gas prices and operating and capital costs assumptions, among others. Because of the complexity involved in estimating oil and gas reserves, management used an independent petroleum engineering consulting firm to audit the estimates prepared by the Company’s engineering technical team for at least 80% of the Company’s total calculated proved reserve PV-10 as of December 31, 2019.
Auditing the Company’s DD&A calculation is especially complex and judgmental because of our use of the work of the Company’s engineering technical team and independent petroleum engineering consulting firm and the evaluation of management’s determination of the inputs described above used by the engineering technical team and independent petroleum engineering consulting firm in estimating proved oil and gas reserves.
|
How We Addressed the Matter in Our Audit
|
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the Company’s engineering technical team and independent petroleum engineering consulting firm for use in estimating the proved oil and gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the engineering technical team primarily responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineering consulting firm used to audit the estimates. In addition, in assessing whether we can use the work of the Company’s engineering technical team and independent petroleum engineering consulting firm we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineering technical team and independent petroleum engineering consulting firm in estimating proved oil and gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved oil and gas reserve amounts used to the Company’s reserve report.
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
10
|
|
|
$
|
77,965
|
|
Accounts receivable
|
184,732
|
|
|
167,536
|
|
||
Derivative assets
|
55,184
|
|
|
175,130
|
|
||
Prepaid expenses and other
|
12,708
|
|
|
8,632
|
|
||
Total current assets
|
252,634
|
|
|
429,263
|
|
||
Property and equipment (successful efforts method):
|
|
|
|
||||
Proved oil and gas properties
|
8,934,020
|
|
|
7,278,362
|
|
||
Accumulated depletion, depreciation, and amortization
|
(4,177,876
|
)
|
|
(3,417,953
|
)
|
||
Unproved oil and gas properties
|
1,005,887
|
|
|
1,581,401
|
|
||
Wells in progress
|
118,769
|
|
|
295,529
|
|
||
Other property and equipment, net of accumulated depreciation of $64,032 and $57,102, respectively
|
72,848
|
|
|
93,826
|
|
||
Total property and equipment, net
|
5,953,648
|
|
|
5,831,165
|
|
||
Noncurrent assets:
|
|
|
|
||||
Derivative assets
|
20,624
|
|
|
58,499
|
|
||
Other noncurrent assets
|
65,326
|
|
|
33,935
|
|
||
Total noncurrent assets
|
85,950
|
|
|
92,434
|
|
||
Total assets
|
$
|
6,292,232
|
|
|
$
|
6,352,862
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses
|
$
|
402,008
|
|
|
$
|
403,199
|
|
Derivative liabilities
|
50,846
|
|
|
62,853
|
|
||
Other current liabilities
|
19,189
|
|
|
—
|
|
||
Total current liabilities
|
472,043
|
|
|
466,052
|
|
||
Noncurrent liabilities:
|
|
|
|
||||
Revolving credit facility
|
122,500
|
|
|
—
|
|
||
Senior Notes, net of unamortized deferred financing costs
|
2,453,035
|
|
|
2,448,439
|
|
||
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
157,263
|
|
|
147,894
|
|
||
Asset retirement obligations
|
84,134
|
|
|
91,859
|
|
||
Deferred income taxes
|
189,386
|
|
|
223,278
|
|
||
Derivative liabilities
|
3,444
|
|
|
12,496
|
|
||
Other noncurrent liabilities
|
61,433
|
|
|
42,522
|
|
||
Total noncurrent liabilities
|
3,071,195
|
|
|
2,966,488
|
|
||
|
|
|
|
||||
Commitments and contingencies (note 6)
|
|
|
|
||||
|
|
|
|
||||
Stockholders’ equity:
|
|
|
|
||||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,987,952 and 112,241,966 shares, respectively
|
1,130
|
|
|
1,122
|
|
||
Additional paid-in capital
|
1,791,596
|
|
|
1,765,738
|
|
||
Retained earnings
|
967,587
|
|
|
1,165,842
|
|
||
Accumulated other comprehensive loss
|
(11,319
|
)
|
|
(12,380
|
)
|
||
Total stockholders’ equity
|
2,748,994
|
|
|
2,920,322
|
|
||
Total liabilities and stockholders’ equity
|
$
|
6,292,232
|
|
|
$
|
6,352,862
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Operating revenues and other income:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production revenue
|
$
|
1,585,750
|
|
|
$
|
1,636,357
|
|
|
$
|
1,253,783
|
|
Net gain (loss) on divestiture activity
|
862
|
|
|
426,917
|
|
|
(131,028
|
)
|
|||
Other operating revenues
|
3,493
|
|
|
3,798
|
|
|
6,621
|
|
|||
Total operating revenues and other income
|
1,590,105
|
|
|
2,067,072
|
|
|
1,129,376
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production expense
|
500,709
|
|
|
487,367
|
|
|
507,906
|
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
823,798
|
|
|
665,313
|
|
|
557,036
|
|
|||
Exploration
|
51,500
|
|
|
55,166
|
|
|
54,713
|
|
|||
Impairment of oil and gas properties
|
33,842
|
|
|
49,889
|
|
|
16,078
|
|
|||
General and administrative
|
132,797
|
|
|
116,504
|
|
|
117,283
|
|
|||
Net derivative (gain) loss
|
97,539
|
|
|
(161,832
|
)
|
|
26,414
|
|
|||
Other operating expenses, net
|
19,888
|
|
|
18,328
|
|
|
13,667
|
|
|||
Total operating expenses
|
1,660,073
|
|
|
1,230,735
|
|
|
1,293,097
|
|
|||
Income (loss) from operations
|
(69,968
|
)
|
|
836,337
|
|
|
(163,721
|
)
|
|||
Interest expense
|
(159,102
|
)
|
|
(160,906
|
)
|
|
(179,257
|
)
|
|||
Loss on extinguishment of debt
|
—
|
|
|
(26,740
|
)
|
|
(35
|
)
|
|||
Other non-operating income (expense), net
|
(1,974
|
)
|
|
3,086
|
|
|
(800
|
)
|
|||
Income (loss) before income taxes
|
(231,044
|
)
|
|
651,777
|
|
|
(343,813
|
)
|
|||
Income tax (expense) benefit
|
44,043
|
|
|
(143,370
|
)
|
|
182,970
|
|
|||
Net income (loss)
|
$
|
(187,001
|
)
|
|
$
|
508,407
|
|
|
$
|
(160,843
|
)
|
|
|
|
|
|
|
||||||
Basic weighted-average common shares outstanding
|
112,544
|
|
|
111,912
|
|
|
111,428
|
|
|||
Diluted weighted-average common shares outstanding
|
112,544
|
|
|
113,502
|
|
|
111,428
|
|
|||
Basic net income (loss) per common share
|
$
|
(1.66
|
)
|
|
$
|
4.54
|
|
|
$
|
(1.44
|
)
|
Diluted net income (loss) per common share
|
$
|
(1.66
|
)
|
|
$
|
4.48
|
|
|
$
|
(1.44
|
)
|
|
For the Years Ended
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Net income (loss)
|
$
|
(187,001
|
)
|
|
$
|
508,407
|
|
|
$
|
(160,843
|
)
|
Other comprehensive income, net of tax:
|
|
|
|
|
|
||||||
Pension liability adjustment (1)
|
1,061
|
|
|
4,378
|
|
|
767
|
|
|||
Total other comprehensive income, net of tax
|
1,061
|
|
|
4,378
|
|
|
767
|
|
|||
Total comprehensive income (loss)
|
$
|
(185,940
|
)
|
|
$
|
512,785
|
|
|
$
|
(160,076
|
)
|
(1)
|
Please refer to Note 8 – Pension Benefits for additional discussion on the pension liability adjustment.
|
|
|
|
Additional Paid-in Capital
|
|
|
|
Accumulated Other Comprehensive Loss
|
|
Total Stockholders’ Equity
|
|||||||||||||
|
Common Stock
|
|
|
Retained Earnings
|
|
|
||||||||||||||||
|
Shares
|
|
Amount
|
|
|
|
|
|||||||||||||||
Balances, January 1, 2017
|
111,257,500
|
|
|
$
|
1,113
|
|
|
$
|
1,716,556
|
|
|
$
|
794,020
|
|
|
$
|
(14,556
|
)
|
|
$
|
2,497,133
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(160,843
|
)
|
|
—
|
|
|
(160,843
|
)
|
|||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
767
|
|
|
767
|
|
|||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,144
|
)
|
|
—
|
|
|
(11,144
|
)
|
|||||
Issuance of common stock under Employee Stock Purchase Plan
|
186,665
|
|
|
2
|
|
|
2,621
|
|
|
—
|
|
|
—
|
|
|
2,623
|
|
|||||
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings
|
171,278
|
|
|
1
|
|
|
(1,241
|
)
|
|
—
|
|
|
—
|
|
|
(1,240
|
)
|
|||||
Stock-based compensation expense
|
71,573
|
|
|
1
|
|
|
22,699
|
|
|
—
|
|
|
—
|
|
|
22,700
|
|
|||||
Cumulative effect of accounting change (1)
|
—
|
|
|
—
|
|
|
1,108
|
|
|
43,624
|
|
|
—
|
|
|
44,732
|
|
|||||
Other
|
—
|
|
|
—
|
|
|
(120
|
)
|
|
—
|
|
|
—
|
|
|
(120
|
)
|
|||||
Balances, December 31, 2017
|
111,687,016
|
|
|
$
|
1,117
|
|
|
$
|
1,741,623
|
|
|
$
|
665,657
|
|
|
$
|
(13,789
|
)
|
|
$
|
2,394,608
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
508,407
|
|
|
—
|
|
|
508,407
|
|
|||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,378
|
|
|
4,378
|
|
|||||
Cash dividends, $0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,191
|
)
|
|
—
|
|
|
(11,191
|
)
|
|||||
Issuance of common stock under Employee Stock Purchase Plan
|
199,464
|
|
|
2
|
|
|
3,185
|
|
|
—
|
|
|
—
|
|
|
3,187
|
|
|||||
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings
|
291,745
|
|
|
3
|
|
|
(2,978
|
)
|
|
—
|
|
|
—
|
|
|
(2,975
|
)
|
|||||
Stock-based compensation expense
|
63,741
|
|
|
—
|
|
|
23,908
|
|
|
—
|
|
|
—
|
|
|
23,908
|
|
|||||
Cumulative effect of accounting change (1)
|
—
|
|
|
—
|
|
|
—
|
|
|
2,969
|
|
|
(2,969
|
)
|
|
—
|
|
|||||
Balances, December 31, 2018
|
112,241,966
|
|
|
$
|
1,122
|
|
|
$
|
1,765,738
|
|
|
$
|
1,165,842
|
|
|
$
|
(12,380
|
)
|
|
$
|
2,920,322
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(187,001
|
)
|
|
—
|
|
|
(187,001
|
)
|
|||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,061
|
|
|
1,061
|
|
|||||
Cash dividends declared, $0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,254
|
)
|
|
—
|
|
|
(11,254
|
)
|
|||||
Issuance of common stock under Employee Stock Purchase Plan
|
314,868
|
|
|
3
|
|
|
3,206
|
|
|
—
|
|
|
—
|
|
|
3,209
|
|
|||||
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings
|
334,399
|
|
|
4
|
|
|
(1,665
|
)
|
|
—
|
|
|
—
|
|
|
(1,661
|
)
|
|||||
Stock-based compensation expense
|
96,719
|
|
|
1
|
|
|
24,317
|
|
|
—
|
|
|
—
|
|
|
24,318
|
|
|||||
Balances, December 31, 2019
|
112,987,952
|
|
|
$
|
1,130
|
|
|
$
|
1,791,596
|
|
|
$
|
967,587
|
|
|
$
|
(11,319
|
)
|
|
$
|
2,748,994
|
|
(1)
|
Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.
|
|
For the Years Ended
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(187,001
|
)
|
|
$
|
508,407
|
|
|
$
|
(160,843
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Net (gain) loss on divestiture activity
|
(862
|
)
|
|
(426,917
|
)
|
|
131,028
|
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
823,798
|
|
|
665,313
|
|
|
557,036
|
|
|||
Impairment of oil and gas properties
|
33,842
|
|
|
49,889
|
|
|
16,078
|
|
|||
Stock-based compensation expense
|
24,318
|
|
|
23,908
|
|
|
22,700
|
|
|||
Net derivative (gain) loss
|
97,539
|
|
|
(161,832
|
)
|
|
26,414
|
|
|||
Derivative settlement gain (loss)
|
39,222
|
|
|
(135,803
|
)
|
|
21,234
|
|
|||
Amortization of debt discount and deferred financing costs
|
15,474
|
|
|
15,258
|
|
|
16,276
|
|
|||
Loss on extinguishment of debt
|
—
|
|
|
26,740
|
|
|
35
|
|
|||
Deferred income taxes
|
(41,835
|
)
|
|
141,708
|
|
|
(192,066
|
)
|
|||
Other, net
|
2,220
|
|
|
287
|
|
|
7,885
|
|
|||
Changes in current assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
(39,556
|
)
|
|
(20,775
|
)
|
|
20,410
|
|
|||
Prepaid expenses and other
|
6,130
|
|
|
(729
|
)
|
|
(1,953
|
)
|
|||
Accounts payable and accrued expenses
|
50,278
|
|
|
35,175
|
|
|
51,156
|
|
|||
Net cash provided by operating activities
|
823,567
|
|
|
720,629
|
|
|
515,390
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Net proceeds from the sale of oil and gas properties
|
13,059
|
|
|
748,509
|
|
|
776,719
|
|
|||
Capital expenditures
|
(1,023,769
|
)
|
|
(1,303,188
|
)
|
|
(888,353
|
)
|
|||
Acquisition of proved and unproved oil and gas properties
|
(2,581
|
)
|
|
(33,255
|
)
|
|
(89,896
|
)
|
|||
Net cash used in investing activities
|
(1,013,291
|
)
|
|
(587,934
|
)
|
|
(201,530
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from credit facility
|
1,589,000
|
|
|
—
|
|
|
406,000
|
|
|||
Repayment of credit facility
|
(1,466,500
|
)
|
|
—
|
|
|
(406,000
|
)
|
|||
Net proceeds from Senior Notes
|
—
|
|
|
492,079
|
|
|
—
|
|
|||
Cash paid to repurchase Senior Notes, including premium
|
—
|
|
|
(845,002
|
)
|
|
(2,357
|
)
|
|||
Net proceeds from sale of common stock
|
3,209
|
|
|
3,187
|
|
|
2,623
|
|
|||
Dividends paid
|
(11,254
|
)
|
|
(11,191
|
)
|
|
(11,144
|
)
|
|||
Other, net
|
(2,686
|
)
|
|
(7,746
|
)
|
|
(1,411
|
)
|
|||
Net cash provided by (used in) financing activities
|
111,769
|
|
|
(368,673
|
)
|
|
(12,289
|
)
|
|||
Net change in cash, cash equivalents, and restricted cash
|
(77,955
|
)
|
|
(235,978
|
)
|
|
301,571
|
|
|||
Cash, cash equivalents, and restricted cash at beginning of period
|
77,965
|
|
|
313,943
|
|
|
12,372
|
|
|||
Cash, cash equivalents, and restricted cash at end of period
|
$
|
10
|
|
|
$
|
77,965
|
|
|
$
|
313,943
|
|
|
|
|
|
|
|
||||||
Supplemental schedule of additional cash flow information and non-cash activities:
|
|
|
|
|
|
||||||
Operating activities:
|
|
|
|
|
|
||||||
Cash paid for interest, net of capitalized interest
|
$
|
(141,902
|
)
|
|
$
|
(150,727
|
)
|
|
$
|
(164,097
|
)
|
Net cash (paid) refunded for income taxes
|
$
|
6,109
|
|
|
$
|
(2,995
|
)
|
|
$
|
(5,986
|
)
|
Investing activities:
|
|
|
|
|
|
||||||
Changes in capital expenditure accruals and other
|
$
|
(24,289
|
)
|
|
$
|
(2,774
|
)
|
|
$
|
7,309
|
|
Supplemental non-cash investing activities:
|
|
|
|
|
|
||||||
Carrying value of properties exchanged
|
$
|
73,442
|
|
|
$
|
95,121
|
|
|
$
|
293,963
|
|
Supplemental non-cash financing activities:
|
|
|
|
|
|
||||||
Non-cash loss on extinguishment of debt, net
|
$
|
—
|
|
|
$
|
6,334
|
|
|
$
|
22
|
|
|
For the Years Ended December 31,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
Major customer #1 (1)
|
18
|
%
|
|
18
|
%
|
|
6
|
%
|
Major customer #2 (1)
|
14
|
%
|
|
5
|
%
|
|
1
|
%
|
Major customer #3 (1)
|
13
|
%
|
|
7
|
%
|
|
—
|
%
|
Major customer #4 (1)
|
9
|
%
|
|
10
|
%
|
|
10
|
%
|
Group #1 of entities under common control (2)
|
13
|
%
|
|
18
|
%
|
|
17
|
%
|
Group #2 of entities under common control (2)
|
11
|
%
|
|
12
|
%
|
|
8
|
%
|
(1)
|
These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets.
|
(2)
|
In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of the Company’s total oil, gas, and NGL production revenue.
|
•
|
On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Effective January 1, 2017, excess tax benefits are presented in net cash provided by operating activities on the accompanying statements of cash flows.
|
•
|
On January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in an increase in additional paid-in capital of $1.1 million, a decrease in deferred tax assets of $400,000, and a net $700,000 cumulative effect decrease to retained earnings.
|
•
|
Under this new guidance, excess tax benefits and deficiencies from share-based payments impact the Company’s effective tax rate between periods.
|
|
For the year ended December 31, 2019
|
||||||||||
|
Midland Basin
|
|
South Texas
|
|
Total
|
||||||
|
(in thousands)
|
||||||||||
Oil production revenue
|
$
|
1,119,786
|
|
|
$
|
63,426
|
|
|
$
|
1,183,212
|
|
Gas production revenue
|
75,827
|
|
|
186,702
|
|
|
262,529
|
|
|||
NGL production revenue
|
123
|
|
|
139,886
|
|
|
140,009
|
|
|||
Total
|
$
|
1,195,736
|
|
|
$
|
390,014
|
|
|
$
|
1,585,750
|
|
Relative percentage
|
75
|
%
|
|
25
|
%
|
|
100
|
%
|
|
For the year ended December 31, 2018
|
||||||||||||||
|
Midland Basin
|
|
South Texas
|
|
Rocky Mountain
|
|
Total
|
||||||||
|
(in thousands)
|
||||||||||||||
Oil production revenue
|
$
|
938,004
|
|
|
$
|
72,821
|
|
|
$
|
54,851
|
|
|
$
|
1,065,676
|
|
Gas production revenue
|
125,603
|
|
|
227,252
|
|
|
1,595
|
|
|
354,450
|
|
||||
NGL production revenue
|
1,000
|
|
|
214,441
|
|
|
790
|
|
|
216,231
|
|
||||
Total
|
$
|
1,064,607
|
|
|
$
|
514,514
|
|
|
$
|
57,236
|
|
|
$
|
1,636,357
|
|
Relative percentage
|
65
|
%
|
|
32
|
%
|
|
3
|
%
|
|
100
|
%
|
|
For the year ended December 31, 2017
|
||||||||||||||
|
Midland Basin
|
|
South Texas
|
|
Rocky Mountain
|
|
Total
|
||||||||
|
(in thousands)
|
||||||||||||||
Oil production revenue
|
$
|
419,732
|
|
|
$
|
82,674
|
|
|
$
|
151,844
|
|
|
$
|
654,250
|
|
Gas production revenue
|
61,781
|
|
|
301,780
|
|
|
5,849
|
|
|
369,410
|
|
||||
NGL production revenue
|
547
|
|
|
226,031
|
|
|
3,545
|
|
|
230,123
|
|
||||
Total
|
$
|
482,060
|
|
|
$
|
610,485
|
|
|
$
|
161,238
|
|
|
$
|
1,253,783
|
|
Relative percentage
|
38
|
%
|
|
49
|
%
|
|
13
|
%
|
|
100
|
%
|
•
|
The Company sells oil and gas production at or near the wellhead and receives an agreed-upon market price from the purchaser. Under this type of arrangement, control transfers at or near the wellhead.
|
•
|
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 the processor realizes from selling the NGLs to 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 fees and other deductions 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 Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Loss before income taxes (1)
|
$
|
—
|
|
|
$
|
(28,975
|
)
|
|
$
|
(468,786
|
)
|
(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. During the year ended December 31, 2017, the Company recorded a write-down of $523.6 million on these assets.
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Current portion of income tax expense (benefit)
|
|
|
|
|
|
||||||
Federal
|
$
|
(3,826
|
)
|
|
$
|
—
|
|
|
$
|
5,698
|
|
State
|
1,618
|
|
|
1,662
|
|
|
3,398
|
|
|||
Deferred portion of income tax expense (benefit)
|
(41,835
|
)
|
|
141,708
|
|
|
(192,066
|
)
|
|||
Income tax expense (benefit)
|
$
|
(44,043
|
)
|
|
$
|
143,370
|
|
|
$
|
(182,970
|
)
|
|
|
|
|
|
|
||||||
Effective tax rate
|
19.1
|
%
|
|
22.0
|
%
|
|
53.2
|
%
|
|
As of December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Deferred tax liabilities
|
|
|
|
||||
Oil and gas properties
|
$
|
205,028
|
|
|
$
|
218,094
|
|
Derivative assets
|
4,646
|
|
|
35,247
|
|
||
Other
|
12,361
|
|
|
4,812
|
|
||
Total deferred tax liabilities
|
222,035
|
|
|
258,153
|
|
||
Deferred tax assets
|
|
|
|
|
|
||
Credit carryover
|
11,270
|
|
|
22,554
|
|
||
Pension
|
5,971
|
|
|
6,427
|
|
||
Federal and state tax net operating loss carryovers
|
4,172
|
|
|
4,217
|
|
||
Stock compensation
|
3,503
|
|
|
3,263
|
|
||
Other liabilities
|
10,803
|
|
|
1,497
|
|
||
Total deferred tax assets
|
35,719
|
|
|
37,958
|
|
||
Valuation allowance
|
(3,070
|
)
|
|
(3,083
|
)
|
||
Net deferred tax assets
|
32,649
|
|
|
34,875
|
|
||
Total net deferred tax liabilities
|
$
|
189,386
|
|
|
$
|
223,278
|
|
|
|
|
|
||||
Current federal income tax refundable
|
$
|
3,885
|
|
|
$
|
59
|
|
Current state income tax payable
|
$
|
1,404
|
|
|
$
|
1,331
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Federal statutory tax expense (benefit)
|
$
|
(48,519
|
)
|
|
$
|
136,873
|
|
|
$
|
(120,335
|
)
|
Increase (decrease) in tax resulting from:
|
|
|
|
|
|
||||||
Federal tax reform changes - 2017 Tax Act
|
—
|
|
|
—
|
|
|
(63,675
|
)
|
|||
State tax expense (benefit) (net of federal benefit)
|
260
|
|
|
2,771
|
|
|
(3,286
|
)
|
|||
Change in valuation allowance
|
(13
|
)
|
|
105
|
|
|
(2,727
|
)
|
|||
Employee share-based compensation
|
3,346
|
|
|
2,508
|
|
|
8,190
|
|
|||
Other
|
883
|
|
|
1,113
|
|
|
(1,137
|
)
|
|||
Income tax expense (benefit)
|
$
|
(44,043
|
)
|
|
$
|
143,370
|
|
|
$
|
(182,970
|
)
|
Borrowing Base Utilization Percentage
|
<25%
|
|
≥25% <50%
|
|
≥50% <75%
|
|
≥75% <90%
|
|
≥90%
|
|||||
Eurodollar Loans (1)
|
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
|
%
|
(1)
|
The Company’s Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it shall no longer be used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the borrower.
|
|
As of February 6, 2020
|
|
As of December 31, 2019
|
|
As of December 31, 2018
|
||||||
|
(in thousands)
|
||||||||||
Revolving credit facility (1)
|
$
|
113,500
|
|
|
$
|
122,500
|
|
|
$
|
—
|
|
Letters of credit (2)
|
—
|
|
|
—
|
|
|
200
|
|
|||
Available borrowing capacity
|
1,086,500
|
|
|
1,077,500
|
|
|
999,800
|
|
|||
Total aggregate lender commitment amount
|
$
|
1,200,000
|
|
|
$
|
1,200,000
|
|
|
$
|
1,000,000
|
|
(1)
|
Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $5.9 million and $6.4 million as of December 31, 2019, and 2018, 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. The letter of credit outstanding as of December 31, 2018, was released effective January 8, 2019.
|
|
As of December 31,
|
||||||||||||||||||||||
|
2019
|
|
2018
|
||||||||||||||||||||
|
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)
|
||||||||||||||||||||||
6.125% Senior Notes due 2022
|
$
|
476,796
|
|
|
$
|
2,920
|
|
|
$
|
473,876
|
|
|
$
|
476,796
|
|
|
$
|
3,921
|
|
|
$
|
472,875
|
|
5.0% Senior Notes due 2024
|
500,000
|
|
|
3,766
|
|
|
496,234
|
|
|
500,000
|
|
|
4,688
|
|
|
495,312
|
|
||||||
5.625% Senior Notes due 2025
|
500,000
|
|
|
4,903
|
|
|
495,097
|
|
|
500,000
|
|
|
5,808
|
|
|
494,192
|
|
||||||
6.75% Senior Notes due 2026
|
500,000
|
|
|
5,571
|
|
|
494,429
|
|
|
500,000
|
|
|
6,407
|
|
|
493,593
|
|
||||||
6.625% Senior Notes due 2027
|
500,000
|
|
|
6,601
|
|
|
493,399
|
|
|
500,000
|
|
|
7,533
|
|
|
492,467
|
|
||||||
Total
|
$
|
2,476,796
|
|
|
$
|
23,761
|
|
|
$
|
2,453,035
|
|
|
$
|
2,476,796
|
|
|
$
|
28,357
|
|
|
$
|
2,448,439
|
|
|
As of December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Principal amount of Senior Convertible Notes
|
$
|
172,500
|
|
|
$
|
172,500
|
|
Unamortized debt discount
|
(13,861
|
)
|
|
(22,313
|
)
|
||
Unamortized deferred financing costs
|
(1,376
|
)
|
|
(2,293
|
)
|
||
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
$
|
157,263
|
|
|
$
|
147,894
|
|
Years Ending December 31,
|
|
Amount
(in thousands)
|
||
2020
|
|
$
|
102,550
|
|
2021
|
|
94,494
|
|
|
2022
|
|
73,826
|
|
|
2023
|
|
41,661
|
|
|
2024
|
|
12,349
|
|
|
Thereafter
|
|
24,697
|
|
|
Total
|
|
$
|
349,577
|
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||
|
PSUs (1)
|
|
Weighted-Average Grant-Date Fair Value
|
|
PSUs (1)
|
|
Weighted-Average Grant-Date Fair Value
|
|
PSUs (1)
|
|
Weighted-Average Grant-Date Fair Value
|
|||||||||
Non-vested at beginning of year
|
1,711,259
|
|
|
$
|
20.68
|
|
|
1,533,491
|
|
|
$
|
22.97
|
|
|
828,923
|
|
|
$
|
43.25
|
|
Granted
|
793,125
|
|
|
$
|
12.80
|
|
|
572,924
|
|
|
$
|
24.45
|
|
|
977,731
|
|
|
$
|
15.86
|
|
Vested
|
(346,021
|
)
|
|
$
|
26.32
|
|
|
(233,102
|
)
|
|
$
|
44.25
|
|
|
(94,338
|
)
|
|
$
|
85.85
|
|
Forfeited
|
(135,778
|
)
|
|
$
|
16.98
|
|
|
(162,054
|
)
|
|
$
|
21.79
|
|
|
(178,825
|
)
|
|
$
|
44.99
|
|
Non-vested at end of year
|
2,022,585
|
|
|
$
|
16.87
|
|
|
1,711,259
|
|
|
$
|
20.68
|
|
|
1,533,491
|
|
|
$
|
22.97
|
|
(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.
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||
|
RSUs
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
RSUs
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
RSUs
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|||||||||
Non-vested at beginning of year
|
1,243,163
|
|
|
$
|
21.50
|
|
|
1,244,262
|
|
|
$
|
20.25
|
|
|
604,116
|
|
|
$
|
37.39
|
|
Granted
|
978,932
|
|
|
$
|
12.36
|
|
|
583,552
|
|
|
$
|
25.77
|
|
|
1,020,780
|
|
|
$
|
16.64
|
|
Vested
|
(466,535
|
)
|
|
$
|
21.94
|
|
|
(407,529
|
)
|
|
$
|
24.30
|
|
|
(246,025
|
)
|
|
$
|
43.99
|
|
Forfeited
|
(223,429
|
)
|
|
$
|
18.16
|
|
|
(177,122
|
)
|
|
$
|
17.26
|
|
|
(134,609
|
)
|
|
$
|
26.38
|
|
Non-vested at end of year
|
1,532,131
|
|
|
$
|
16.01
|
|
|
1,243,163
|
|
|
$
|
21.50
|
|
|
1,244,262
|
|
|
$
|
20.25
|
|
|
For the Years Ended December 31,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
Shares of common stock issued to settle RSUs (1)
|
466,535
|
|
|
407,529
|
|
|
246,025
|
|
Less: shares of common stock withheld for income and payroll taxes
|
(132,136
|
)
|
|
(115,784
|
)
|
|
(74,747
|
)
|
Net shares of common stock issued
|
334,399
|
|
|
291,745
|
|
|
171,278
|
|
(1)
|
During the years ended December 31, 2019, 2018, and 2017, the Company issued shares of common stock to settle RSUs that related to awards granted in previous years. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.
|
|
For the Years Ended December 31,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
Risk free interest rate
|
2.3
|
%
|
|
1.8
|
%
|
|
0.9
|
%
|
Dividend yield
|
0.7
|
%
|
|
0.4
|
%
|
|
0.5
|
%
|
Volatility factor of the expected market
price of the Company’s common stock
|
56.6
|
%
|
|
55.9
|
%
|
|
62.5
|
%
|
Expected life (in years)
|
0.5
|
|
|
0.5
|
|
|
0.5
|
|
|
For the Years Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Change in benefit obligation:
|
|
|
|
||||
Projected benefit obligation at beginning of year
|
$
|
66,086
|
|
|
$
|
71,937
|
|
Service cost
|
5,582
|
|
|
6,730
|
|
||
Interest cost
|
2,791
|
|
|
2,622
|
|
||
Actuarial (gain) loss
|
2,035
|
|
|
(7,155
|
)
|
||
Benefits paid
|
(5,651
|
)
|
|
(8,048
|
)
|
||
Projected benefit obligation at end of year
|
70,843
|
|
|
66,086
|
|
||
|
|
|
|
||||
Change in plan assets:
|
|
|
|
||||
Fair value of plan assets at beginning of year
|
30,100
|
|
|
30,978
|
|
||
Actual return (loss) on plan assets
|
3,985
|
|
|
(964
|
)
|
||
Employer contribution
|
7,200
|
|
|
8,134
|
|
||
Benefits paid
|
(5,651
|
)
|
|
(8,048
|
)
|
||
Fair value of plan assets at end of year
|
35,634
|
|
|
30,100
|
|
||
Funded status at end of year
|
$
|
(35,209
|
)
|
|
$
|
(35,986
|
)
|
|
As of December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Projected benefit obligation
|
$
|
70,843
|
|
|
$
|
66,086
|
|
|
|
|
|
||||
Accumulated benefit obligation
|
$
|
60,877
|
|
|
$
|
52,368
|
|
Less: fair value of plan assets
|
(35,634
|
)
|
|
(30,100
|
)
|
||
Underfunded accumulated benefit obligation
|
$
|
25,243
|
|
|
$
|
22,268
|
|
|
As of December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Unrecognized actuarial losses
|
$
|
14,406
|
|
|
$
|
15,741
|
|
Unrecognized prior service costs
|
31
|
|
|
48
|
|
||
Accumulated other comprehensive loss
|
$
|
14,437
|
|
|
$
|
15,789
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Net actuarial gain (loss)
|
$
|
377
|
|
|
$
|
4,329
|
|
|
$
|
(2,995
|
)
|
Amortization of prior service cost
|
17
|
|
|
18
|
|
|
17
|
|
|||
Amortization of net actuarial loss
|
958
|
|
|
1,327
|
|
|
1,297
|
|
|||
Settlements
|
—
|
|
|
—
|
|
|
3,009
|
|
|||
Total pension liability adjustment, pre-tax
|
1,352
|
|
|
5,674
|
|
|
1,328
|
|
|||
Tax expense
|
(291
|
)
|
|
(4,265
|
)
|
|
(561
|
)
|
|||
Cumulative effect of accounting change (1)
|
—
|
|
|
2,969
|
|
|
—
|
|
|||
Total pension liability adjustment, net
|
$
|
1,061
|
|
|
$
|
4,378
|
|
|
$
|
767
|
|
(1)
|
Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies and Statements of Stockholders’ Equity for additional information.
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
||||||
Service cost
|
$
|
5,582
|
|
|
$
|
6,730
|
|
|
$
|
6,638
|
|
Interest cost
|
2,791
|
|
|
2,622
|
|
|
2,689
|
|
|||
Expected return on plan assets that reduces periodic pension benefit cost
|
(1,574
|
)
|
|
(1,862
|
)
|
|
(2,244
|
)
|
|||
Amortization of prior service cost
|
17
|
|
|
18
|
|
|
17
|
|
|||
Amortization of net actuarial loss
|
958
|
|
|
1,327
|
|
|
1,297
|
|
|||
Settlements
|
—
|
|
|
—
|
|
|
3,009
|
|
|||
Net periodic benefit cost
|
$
|
7,774
|
|
|
$
|
8,835
|
|
|
$
|
11,406
|
|
|
As of December 31,
|
||
|
2019
|
|
2018
|
Projected benefit obligation:
|
|
|
|
Discount rate
|
3.6%
|
|
4.4%
|
Rate of compensation increase
|
4.5%
|
|
6.2%
|
|
For the Years Ended December 31,
|
||||
|
2019
|
|
2018
|
|
2017
|
Net periodic benefit cost:
|
|
|
|
|
|
Discount rate
|
4.4%
|
|
3.8%
|
|
4.2%
|
Expected return on plan assets (1)
|
5.0%
|
|
5.5%
|
|
6.5%
|
Rate of compensation increase
|
6.2%
|
|
6.2%
|
|
6.2%
|
(1)
|
There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan.
|
|
|
Target
|
|
As of December 31,
|
|||||
Asset Category
|
|
2020
|
|
2019
|
|
2018
|
|||
Equity securities
|
|
35.0
|
%
|
|
36.9
|
%
|
|
31.8
|
%
|
Fixed income securities
|
|
40.0
|
%
|
|
38.1
|
%
|
|
41.3
|
%
|
Other securities
|
|
25.0
|
%
|
|
25.0
|
%
|
|
26.9
|
%
|
Total
|
|
100.0
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
|
|
|
|
|
Fair Value Measurements Using:
|
|||||||||||||
|
Actual Asset Allocation (1)
|
|
Total
|
|
Level 1 Inputs
|
|
Level 2 Inputs
|
|
Level 3 Inputs
|
|||||||||
|
|
|
(in thousands)
|
|||||||||||||||
As of December 31, 2019
|
|
|
|
|
|
|
|
|
|
|||||||||
Equity securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Domestic (2)
|
17.3
|
%
|
|
$
|
6,176
|
|
|
$
|
4,130
|
|
|
$
|
2,046
|
|
|
$
|
—
|
|
International (3)
|
19.6
|
%
|
|
6,958
|
|
|
6,958
|
|
|
—
|
|
|
—
|
|
||||
Total equity securities
|
36.9
|
%
|
|
13,134
|
|
|
11,088
|
|
|
2,046
|
|
|
—
|
|
||||
Fixed income securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Core fixed income (4)
|
31.4
|
%
|
|
11,199
|
|
|
11,199
|
|
|
—
|
|
|
—
|
|
||||
Floating rate corporate loans (5)
|
6.7
|
%
|
|
2,379
|
|
|
2,379
|
|
|
—
|
|
|
—
|
|
||||
Total fixed income securities
|
38.1
|
%
|
|
13,578
|
|
|
13,578
|
|
|
—
|
|
|
—
|
|
||||
Other securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Real estate (6)
|
5.4
|
%
|
|
1,929
|
|
|
—
|
|
|
—
|
|
|
1,929
|
|
||||
Collective investment trusts (7)
|
3.3
|
%
|
|
1,168
|
|
|
—
|
|
|
1,168
|
|
|
—
|
|
||||
Hedge fund (8)
|
16.3
|
%
|
|
5,825
|
|
|
2,006
|
|
|
—
|
|
|
3,819
|
|
||||
Total other securities
|
25.0
|
%
|
|
8,922
|
|
|
2,006
|
|
|
1,168
|
|
|
5,748
|
|
||||
Total investments
|
100.0
|
%
|
|
$
|
35,634
|
|
|
$
|
26,672
|
|
|
$
|
3,214
|
|
|
$
|
5,748
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
As of December 31, 2018
|
|
|
|
|
|
|
|
|
|
|||||||||
Equity securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Domestic (2)
|
15.4
|
%
|
|
$
|
4,639
|
|
|
$
|
3,197
|
|
|
$
|
1,442
|
|
|
$
|
—
|
|
International (3)
|
16.4
|
%
|
|
4,941
|
|
|
3,642
|
|
|
1,299
|
|
|
—
|
|
||||
Total equity securities
|
31.8
|
%
|
|
9,580
|
|
|
6,839
|
|
|
2,741
|
|
|
—
|
|
||||
Fixed income securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Core fixed income (4)
|
34.4
|
%
|
|
10,342
|
|
|
10,342
|
|
|
—
|
|
|
—
|
|
||||
Floating rate corporate loans (5)
|
6.9
|
%
|
|
2,078
|
|
|
2,078
|
|
|
—
|
|
|
—
|
|
||||
Total fixed income securities
|
41.3
|
%
|
|
12,420
|
|
|
12,420
|
|
|
—
|
|
|
—
|
|
||||
Other securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Real estate (6)
|
6.0
|
%
|
|
1,820
|
|
|
—
|
|
|
—
|
|
|
1,820
|
|
||||
Collective investment trusts (7)
|
3.1
|
%
|
|
934
|
|
|
—
|
|
|
934
|
|
|
—
|
|
||||
Hedge fund (8)
|
17.8
|
%
|
|
5,346
|
|
|
—
|
|
|
1,659
|
|
|
3,687
|
|
||||
Total other securities
|
26.9
|
%
|
|
8,100
|
|
|
—
|
|
|
2,593
|
|
|
5,507
|
|
||||
Total investments
|
100.0
|
%
|
|
$
|
30,100
|
|
|
$
|
19,259
|
|
|
$
|
5,334
|
|
|
$
|
5,507
|
|
(1)
|
Percentages may not calculate due to rounding.
|
(2)
|
Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective investment funds.
|
(3)
|
International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations.
|
(4)
|
The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index.
|
(5)
|
Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates.
|
(6)
|
The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity.
|
(7)
|
Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities.
|
(8)
|
The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.
|
Balance at January 1, 2018
|
$
|
5,209
|
|
Purchases
|
—
|
|
|
Realized gain on assets
|
191
|
|
|
Unrealized gain on assets
|
152
|
|
|
Disposition
|
(45
|
)
|
|
Balance at December 31, 2018
|
$
|
5,507
|
|
Purchases
|
—
|
|
|
Realized gain on assets
|
190
|
|
|
Unrealized gain on assets
|
51
|
|
|
Disposition
|
—
|
|
|
Balance at December 31, 2019
|
$
|
5,748
|
|
Years Ending December 31,
|
(in thousands)
|
||
2020
|
$
|
7,609
|
|
2021
|
$
|
3,914
|
|
2022
|
$
|
4,022
|
|
2023
|
$
|
6,308
|
|
2024
|
$
|
4,939
|
|
2025 through 2029
|
$
|
25,065
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands, except per share data)
|
||||||||||
Net income (loss)
|
$
|
(187,001
|
)
|
|
$
|
508,407
|
|
|
$
|
(160,843
|
)
|
|
|
|
|
|
|
||||||
Basic weighted-average common shares outstanding
|
112,544
|
|
|
111,912
|
|
|
111,428
|
|
|||
Dilutive effect of non-vested RSUs and contingent PSUs
|
—
|
|
|
1,590
|
|
|
—
|
|
|||
Diluted weighted-average common shares outstanding
|
112,544
|
|
|
113,502
|
|
|
111,428
|
|
|||
|
|
|
|
|
|
||||||
Basic net income (loss) per common share
|
$
|
(1.66
|
)
|
|
$
|
4.54
|
|
|
$
|
(1.44
|
)
|
Diluted net income (loss) per common share
|
$
|
(1.66
|
)
|
|
$
|
4.48
|
|
|
$
|
(1.44
|
)
|
Contract Period
|
|
NYMEX WTI Volumes
|
|
Weighted-Average
Contract Price
|
|||
|
|
(MBbl)
|
|
(per Bbl)
|
|||
First quarter 2020
|
|
2,486
|
|
|
$
|
59.65
|
|
Second quarter 2020
|
|
2,838
|
|
|
$
|
58.81
|
|
Third quarter 2020
|
|
3,361
|
|
|
$
|
56.43
|
|
Fourth quarter 2020
|
|
3,937
|
|
|
$
|
56.94
|
|
2021
|
|
667
|
|
|
$
|
56.00
|
|
Total
|
|
13,289
|
|
|
|
Contract Period
|
|
NYMEX WTI Volumes
|
|
Weighted-Average
Floor Price
|
|
Weighted-Average
Ceiling Price
|
|||||
|
|
(MBbl)
|
|
(per Bbl)
|
|
(per Bbl)
|
|||||
First quarter 2020
|
|
2,267
|
|
|
$
|
55.00
|
|
|
$
|
63.91
|
|
Second quarter 2020
|
|
1,881
|
|
|
$
|
55.00
|
|
|
$
|
62.17
|
|
Third quarter 2020
|
|
1,252
|
|
|
$
|
55.00
|
|
|
$
|
62.90
|
|
Fourth quarter 2020
|
|
610
|
|
|
$
|
55.00
|
|
|
$
|
61.90
|
|
2021
|
|
329
|
|
|
$
|
55.00
|
|
|
$
|
56.70
|
|
Total
|
|
6,339
|
|
|
|
|
|
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)
|
||||||
First quarter 2020
|
|
4,193
|
|
|
$
|
(0.68
|
)
|
|
—
|
|
|
$
|
—
|
|
Second quarter 2020
|
|
3,495
|
|
|
$
|
(0.68
|
)
|
|
910
|
|
|
$
|
(8.06
|
)
|
Third quarter 2020
|
|
3,325
|
|
|
$
|
(0.74
|
)
|
|
920
|
|
|
$
|
(8.01
|
)
|
Fourth quarter 2020
|
|
3,261
|
|
|
$
|
(0.73
|
)
|
|
920
|
|
|
$
|
(8.01
|
)
|
2021
|
|
5,954
|
|
|
$
|
0.59
|
|
|
3,650
|
|
|
$
|
(7.86
|
)
|
2022
|
|
—
|
|
|
$
|
—
|
|
|
3,650
|
|
|
$
|
(7.78
|
)
|
Total
|
|
20,228
|
|
|
|
|
10,050
|
|
|
|
(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
|
|
IF HSC Volumes
|
|
Weighted-Average Contract Price
|
|
WAHA Volumes
|
|
Weighted-Average Contract Price
|
||||||
|
|
(BBtu)
|
|
(per MMBtu)
|
|
(BBtu)
|
|
(per MMBtu)
|
||||||
First quarter 2020
|
|
9,123
|
|
|
$
|
2.98
|
|
|
3,099
|
|
|
$
|
1.93
|
|
Second quarter 2020
|
|
4,160
|
|
|
$
|
2.20
|
|
|
3,196
|
|
|
$
|
0.56
|
|
Third quarter 2020
|
|
4,493
|
|
|
$
|
2.41
|
|
|
3,268
|
|
|
$
|
1.03
|
|
Fourth quarter 2020
|
|
3,722
|
|
|
$
|
2.36
|
|
|
3,419
|
|
|
$
|
1.17
|
|
2021
|
|
—
|
|
|
$
|
—
|
|
|
4,224
|
|
|
$
|
1.51
|
|
Total (1)
|
|
21,498
|
|
|
|
|
17,206
|
|
|
|
(1)
|
The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of December 31, 2019, WAHA volumes were comprised of 92 percent IF WAHA and eight percent GD WAHA.
|
|
|
OPIS Ethane Purity Mont Belvieu
|
|
OPIS Propane Mont Belvieu Non-TET
|
||||||||||
Contract Period
|
|
Volumes
|
|
Weighted-Average Contract Price
|
|
Volumes
|
|
Weighted-Average Contract Price
|
||||||
|
|
(MBbl)
|
|
(per Bbl)
|
|
(MBbl)
|
|
(per Bbl)
|
||||||
First quarter 2020
|
|
447
|
|
|
$
|
11.53
|
|
|
382
|
|
|
$
|
22.64
|
|
Second quarter 2020
|
|
264
|
|
|
$
|
11.13
|
|
|
382
|
|
|
$
|
22.34
|
|
Third quarter 2020
|
|
—
|
|
|
$
|
—
|
|
|
409
|
|
|
$
|
22.33
|
|
Fourth quarter 2020
|
|
—
|
|
|
$
|
—
|
|
|
466
|
|
|
$
|
22.29
|
|
Total
|
|
711
|
|
|
|
|
1,639
|
|
|
|
•
|
fixed price NYMEX WTI oil swap contracts for the fourth quarter of 2020 through January 2021 for a total of 0.6 MMBbl of oil production at a weighted-average contract price of $57.82 per Bbl; and
|
•
|
fixed price WTI Midland-NYMEX WTI oil basis swap contracts for the second quarter of 2020 through the fourth quarter of 2022 for a total of 16.3 MMBbl of oil production at a weighted-average contract price of $1.14 per Bbl.
|
|
As of December 31, 2019
|
|
As of December 31, 2018
|
||||
|
(in thousands)
|
||||||
Derivative assets:
|
|
|
|
||||
Current assets
|
$
|
55,184
|
|
|
$
|
175,130
|
|
Noncurrent assets
|
20,624
|
|
|
58,499
|
|
||
Total derivative assets
|
$
|
75,808
|
|
|
$
|
233,629
|
|
Derivative liabilities:
|
|
|
|
||||
Current liabilities
|
$
|
50,846
|
|
|
$
|
62,853
|
|
Noncurrent liabilities
|
3,444
|
|
|
12,496
|
|
||
Total derivative liabilities
|
$
|
54,290
|
|
|
$
|
75,349
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||
|
|
As of December 31,
|
|
As of December 31,
|
||||||||||||
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
|
|
(in thousands)
|
||||||||||||||
Gross amounts presented in the accompanying balance sheets
|
|
$
|
75,808
|
|
|
$
|
233,629
|
|
|
$
|
(54,290
|
)
|
|
$
|
(75,349
|
)
|
Amounts not offset in the accompanying balance sheets
|
|
(35,075
|
)
|
|
(56,041
|
)
|
|
35,075
|
|
|
56,041
|
|
||||
Net amounts
|
|
$
|
40,733
|
|
|
$
|
177,588
|
|
|
$
|
(19,215
|
)
|
|
$
|
(19,308
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Derivative settlement (gain) loss:
|
|
|
|
|
|
||||||
Oil contracts
|
$
|
19,685
|
|
|
$
|
68,860
|
|
|
$
|
31,176
|
|
Gas contracts
|
(23,008
|
)
|
|
13,029
|
|
|
(87,857
|
)
|
|||
NGL contracts
|
(35,899
|
)
|
|
53,914
|
|
|
35,447
|
|
|||
Total derivative settlement (gain) loss
|
$
|
(39,222
|
)
|
|
$
|
135,803
|
|
|
$
|
(21,234
|
)
|
|
|
|
|
|
|
||||||
Net derivative (gain) loss:
|
|
|
|
|
|
||||||
Oil contracts
|
$
|
172,055
|
|
|
$
|
(192,002
|
)
|
|
$
|
71,502
|
|
Gas contracts
|
(41,205
|
)
|
|
35,411
|
|
|
(76,315
|
)
|
|||
NGL contracts
|
(33,311
|
)
|
|
(5,241
|
)
|
|
31,227
|
|
|||
Total net derivative (gain) loss
|
$
|
97,539
|
|
|
$
|
(161,832
|
)
|
|
$
|
26,414
|
|
•
|
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)
|
$
|
—
|
|
|
$
|
75,808
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives (1)
|
$
|
—
|
|
|
$
|
54,290
|
|
|
$
|
—
|
|
(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)
|
$
|
—
|
|
|
$
|
233,629
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives (1)
|
$
|
—
|
|
|
$
|
75,349
|
|
|
$
|
—
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in millions)
|
||||||||||
Impairment of proved properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3.8
|
|
Abandonment and impairment of unproved properties
|
33.8
|
|
|
49.9
|
|
|
12.3
|
|
|||
Impairment of oil and gas properties
|
$
|
33.8
|
|
|
$
|
49.9
|
|
|
$
|
16.1
|
|
|
As of December 31,
|
||||||||||||||
|
2019
|
|
2018
|
||||||||||||
|
Principal Amount
|
|
Fair Value
|
|
Principal Amount
|
|
Fair Value
|
||||||||
|
(in thousands)
|
||||||||||||||
6.125% Senior Notes due 2022
|
$
|
476,796
|
|
|
$
|
481,564
|
|
|
$
|
476,796
|
|
|
$
|
452,336
|
|
5.0% Senior Notes due 2024
|
$
|
500,000
|
|
|
$
|
479,815
|
|
|
$
|
500,000
|
|
|
$
|
439,265
|
|
5.625% Senior Notes due 2025
|
$
|
500,000
|
|
|
$
|
475,835
|
|
|
$
|
500,000
|
|
|
$
|
436,460
|
|
6.75% Senior Notes due 2026
|
$
|
500,000
|
|
|
$
|
494,860
|
|
|
$
|
500,000
|
|
|
$
|
448,305
|
|
6.625% Senior Notes due 2027
|
$
|
500,000
|
|
|
$
|
493,750
|
|
|
$
|
500,000
|
|
|
$
|
442,500
|
|
1.50% Senior Convertible Notes due 2021
|
$
|
172,500
|
|
|
$
|
164,430
|
|
|
$
|
172,500
|
|
|
$
|
158,614
|
|
•
|
Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception.
|
•
|
Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company.
|
|
For the Year Ended December 31, 2019
|
||
|
|
||
Operating lease cost
|
$
|
35,570
|
|
Short-term lease cost (1)
|
301,373
|
|
|
Variable lease cost (2)
|
106,006
|
|
|
Total lease cost (3)
|
$
|
442,949
|
|
(1)
|
Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.
|
(2)
|
Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements.
|
(3)
|
Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.
|
|
For the Year Ended December 31, 2019
|
||
|
(in thousands)
|
||
Cash paid for amounts included in the measurement of lease liabilities:
|
|
||
Operating cash flows from operating leases
|
$
|
12,074
|
|
Investing cash flows from operating leases
|
$
|
24,129
|
|
Right-of-use assets obtained in exchange for new operating lease liabilities
|
$
|
25,360
|
|
|
As of December 31, 2019
|
||
|
(in thousands)
|
||
2020
|
$
|
21,102
|
|
2021
|
12,600
|
|
|
2022
|
5,749
|
|
|
2023
|
3,602
|
|
|
2024
|
2,081
|
|
|
Thereafter
|
1,639
|
|
|
Total Lease payments
|
$
|
46,773
|
|
Less: Imputed interest (1)
|
(4,447
|
)
|
|
Total
|
$
|
42,326
|
|
(1)
|
The weighted-average discount rate used to determine the operating lease liability as of December 31, 2019 was 6.6 percent.
|
|
As of December 31, 2019
|
||
|
(in thousands)
|
||
Other noncurrent assets
|
$
|
39,717
|
|
|
|
||
Other current liabilities
|
$
|
19,189
|
|
Other noncurrent liabilities
|
$
|
23,137
|
|
|
As of December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Oil, gas, and NGL production revenue
|
$
|
146,308
|
|
|
$
|
107,230
|
|
Amounts due from joint interest owners
|
22,681
|
|
|
31,497
|
|
||
State severance tax refunds
|
4,069
|
|
|
4,415
|
|
||
Derivative settlements
|
6,868
|
|
|
9,475
|
|
||
Other
|
4,806
|
|
|
14,919
|
|
||
Total accounts receivable
|
$
|
184,732
|
|
|
$
|
167,536
|
|
|
As of December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Drilling and lease operating cost accruals
|
$
|
96,925
|
|
|
$
|
139,711
|
|
Trade accounts payable
|
52,094
|
|
|
56,047
|
|
||
Revenue and severance tax payable
|
109,847
|
|
|
94,806
|
|
||
Property taxes
|
24,535
|
|
|
18,694
|
|
||
Compensation
|
41,540
|
|
|
31,486
|
|
||
Derivative settlements
|
5,851
|
|
|
1,287
|
|
||
Interest
|
44,175
|
|
|
40,840
|
|
||
Other
|
27,041
|
|
|
20,328
|
|
||
Total accounts payable and accrued expenses
|
$
|
402,008
|
|
|
$
|
403,199
|
|
|
As of December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Beginning asset retirement obligations
|
$
|
94,194
|
|
|
$
|
114,470
|
|
Liabilities incurred (1)
|
3,927
|
|
|
4,054
|
|
||
Liabilities settled (2)
|
(4,105
|
)
|
|
(33,024
|
)
|
||
Accretion expense
|
4,016
|
|
|
4,438
|
|
||
Revision to estimated cash flows
|
(11,186
|
)
|
|
4,256
|
|
||
Ending asset retirement obligations (3)
|
$
|
86,846
|
|
|
$
|
94,194
|
|
(1)
|
Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.
|
(2)
|
Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.
|
(3)
|
Balances as of December 31, 2019, and 2018, included $2.7 million and $2.3 million, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets.
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
11,197
|
|
|
$
|
49,446
|
|
|
$
|
19,846
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
11,925
|
|
|
11,197
|
|
|
49,446
|
|
|||
Divestitures
|
—
|
|
|
(109
|
)
|
|
—
|
|
|||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
|
(11,197
|
)
|
|
(49,337
|
)
|
|
(19,846
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance
|
$
|
11,925
|
|
|
$
|
11,197
|
|
|
$
|
49,446
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Development costs (1)
|
$
|
913,959
|
|
|
$
|
1,147,574
|
|
|
$
|
675,523
|
|
Exploration costs
|
114,957
|
|
|
184,930
|
|
|
271,502
|
|
|||
Acquisitions
|
|
|
|
|
|
||||||
Proved properties
|
(310
|
)
|
|
1,312
|
|
|
1,602
|
|
|||
Unproved properties (2)
|
11,633
|
|
|
55,688
|
|
|
91,420
|
|
|||
Total, including asset retirement obligations (3)(4)
|
$
|
1,040,239
|
|
|
$
|
1,389,504
|
|
|
$
|
1,040,047
|
|
(1)
|
Includes facility costs of $28.3 million, $72.6 million, and $43.8 million for the years ended December 31, 2019, 2018, and 2017, respectively.
|
(2)
|
Includes amounts related to leasing activity and acquiring surface rights outside of acquisitions of proved and unproved properties totaling $8.7 million, $23.4 million, and $12.8 million for the years ended December 31, 2019, 2018, and 2017, respectively.
|
(3)
|
Includes amounts relating to estimated asset retirement obligations of $(9.9) million, $7.1 million, and $13.6 million for the years ended December 31, 2019, 2018, and 2017, respectively.
|
(4)
|
Includes capitalized interest of $18.5 million, $20.6 million, and $12.6 million for the years ended December 31, 2019, 2018, and 2017, respectively.
|
|
||||||||||||||||||||||||||
|
For the Years Ended December 31,
|
|||||||||||||||||||||||||
|
2019 (1)
|
|
2018 (2)
|
|
2017 (3)
|
|||||||||||||||||||||
|
Oil
|
|
Gas
|
|
NGLs
|
|
Oil
|
|
Gas
|
|
NGLs
|
|
Oil
|
|
Gas
|
|
NGLs
|
|||||||||
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|||||||||
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Beginning of year
|
175.7
|
|
|
1,321.8
|
|
|
107.4
|
|
|
158.2
|
|
|
1,280.1
|
|
|
96.5
|
|
|
104.9
|
|
|
1,111.1
|
|
|
105.7
|
|
Revisions of previous estimate
|
(19.2
|
)
|
|
(212.5
|
)
|
|
(40.0
|
)
|
|
(24.0
|
)
|
|
(219.5
|
)
|
|
(8.0
|
)
|
|
1.0
|
|
|
63.8
|
|
|
4.9
|
|
Discoveries and extensions
|
5.4
|
|
|
28.8
|
|
|
2.9
|
|
|
9.3
|
|
|
20.3
|
|
|
0.5
|
|
|
11.5
|
|
|
21.9
|
|
|
—
|
|
Infill reserves in an existing proved field
|
41.8
|
|
|
190.2
|
|
|
11.8
|
|
|
80.4
|
|
|
391.5
|
|
|
29.0
|
|
|
79.0
|
|
|
347.4
|
|
|
22.9
|
|
Sales of reserves (4)
|
(0.2
|
)
|
|
(0.7
|
)
|
|
—
|
|
|
(29.6
|
)
|
|
(48.1
|
)
|
|
(2.7
|
)
|
|
(25.3
|
)
|
|
(143.8
|
)
|
|
(26.7
|
)
|
Purchases of minerals in place (4)
|
2.5
|
|
|
5.4
|
|
|
—
|
|
|
0.2
|
|
|
0.7
|
|
|
—
|
|
|
0.8
|
|
|
2.7
|
|
|
—
|
|
Production
|
(21.9
|
)
|
|
(109.8
|
)
|
|
(8.1
|
)
|
|
(18.8
|
)
|
|
(103.2
|
)
|
|
(7.9
|
)
|
|
(13.7
|
)
|
|
(123.0
|
)
|
|
(10.3
|
)
|
End of year
|
184.1
|
|
|
1,223.2
|
|
|
74.0
|
|
|
175.7
|
|
|
1,321.8
|
|
|
107.4
|
|
|
158.2
|
|
|
1,280.1
|
|
|
96.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Beginning of year
|
68.2
|
|
|
699.1
|
|
|
60.1
|
|
|
58.6
|
|
|
642.9
|
|
|
49.0
|
|
|
48.5
|
|
|
609.1
|
|
|
58.6
|
|
End of year
|
85.0
|
|
|
712.1
|
|
|
43.4
|
|
|
68.2
|
|
699.1
|
|
|
60.1
|
|
|
58.6
|
|
642.9
|
|
|
49.0
|
|
||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Beginning of year
|
107.6
|
|
|
622.7
|
|
|
47.2
|
|
|
99.6
|
|
|
637.2
|
|
|
47.6
|
|
|
56.4
|
|
|
502.0
|
|
|
47.1
|
|
End of year
|
99.1
|
|
|
511.1
|
|
|
30.6
|
|
|
107.6
|
|
|
622.7
|
|
|
47.2
|
|
|
99.6
|
|
|
637.2
|
|
|
47.6
|
|
(1)
|
For the year ended December 31, 2019, the Company added 98.4 MMBOE from its drilling program and further development plan optimization. These additions were offset by net downward revisions of 94.7 MMBOE, which were primarily driven by declining commodity prices during 2019. Please refer to Areas of Operation in Part I, Items 1 and 2 of this report, and to Oil and Gas Reserve Quantities in Critical Accounting Policies and Estimates in Part II, Item 7 of this report for additional information.
|
(2)
|
For the year ended December 31, 2018, the Company added 188.0 MMBOE from its drilling program and through development plan optimization. The Company divested 40.3 MMBOE during 2018, primarily as a result of the PRB Divestiture, Divide County Divestiture, and Halff East Divestiture. The Company also had net downward revisions of 68.8 MMBOE, which resulted primarily from changes in development plans in its Eagle Ford shale program.
|
(3)
|
For the year ended December 31, 2017, the Company added 175.0 MMBOE from its drilling program. The Company divested 76.0 MMBOE during 2017, including 72.5 MMBOE related to its outside-operated Eagle Ford shale assets.
|
(4)
|
Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional information.
|
|
As of December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Future cash inflows
|
$
|
14,327,131
|
|
|
$
|
17,579,432
|
|
|
$
|
14,035,704
|
|
Future production costs
|
(4,579,119
|
)
|
|
(5,386,264
|
)
|
|
(5,594,226
|
)
|
|||
Future development costs
|
(2,108,859
|
)
|
|
(2,679,488
|
)
|
|
(2,638,459
|
)
|
|||
Future income taxes
|
(579,815
|
)
|
|
(1,012,209
|
)
|
|
(205,694
|
)
|
|||
Future net cash flows
|
7,059,338
|
|
|
8,501,471
|
|
|
5,597,325
|
|
|||
10 percent annual discount
|
(2,955,340
|
)
|
|
(3,847,088
|
)
|
|
(2,573,183
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
4,103,998
|
|
|
$
|
4,654,383
|
|
|
$
|
3,024,142
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands)
|
||||||||||
Standardized Measure, beginning of year
|
$
|
4,654,383
|
|
|
$
|
3,024,142
|
|
|
$
|
1,152,113
|
|
Sales of oil, gas, and NGLs produced, net of production costs
|
(1,085,041
|
)
|
|
(1,148,991
|
)
|
|
(745,877
|
)
|
|||
Net changes in prices and production costs
|
(1,539,042
|
)
|
|
1,010,335
|
|
|
1,181,447
|
|
|||
Extensions, discoveries and other including infill reserves in an existing proved field, net of related costs
|
887,254
|
|
|
2,218,475
|
|
|
1,638,734
|
|
|||
Sales of reserves in place
|
(2,788
|
)
|
|
(147,887
|
)
|
|
(226,528
|
)
|
|||
Purchase of reserves in place
|
57,519
|
|
|
1,818
|
|
|
12,032
|
|
|||
Previously estimated development costs incurred during the period
|
736,770
|
|
|
445,638
|
|
|
121,879
|
|
|||
Changes in estimated future development costs
|
132,825
|
|
|
(34,871
|
)
|
|
(116,609
|
)
|
|||
Revisions of previous quantity estimates
|
(398,409
|
)
|
|
(611,168
|
)
|
|
103,916
|
|
|||
Accretion of discount
|
510,427
|
|
|
305,657
|
|
|
115,211
|
|
|||
Net change in income taxes
|
191,040
|
|
|
(449,884
|
)
|
|
(32,426
|
)
|
|||
Changes in timing and other
|
(40,940
|
)
|
|
41,119
|
|
|
(179,750
|
)
|
|||
Standardized Measure, end of year
|
$
|
4,103,998
|
|
|
$
|
4,654,383
|
|
|
$
|
3,024,142
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
||||||||
Year Ended December 31, 2019 (1)
|
|
|
|
|
|
|
|
||||||||
Total operating revenues and other income
|
$
|
340,930
|
|
|
$
|
407,172
|
|
|
$
|
390,317
|
|
|
$
|
451,686
|
|
Total operating expenses
|
526,239
|
|
|
303,005
|
|
|
290,840
|
|
|
539,989
|
|
||||
Income (loss) from operations
|
$
|
(185,309
|
)
|
|
$
|
104,167
|
|
|
$
|
99,477
|
|
|
$
|
(88,303
|
)
|
Income (loss) before income taxes
|
$
|
(223,606
|
)
|
|
$
|
63,978
|
|
|
$
|
58,345
|
|
|
$
|
(129,761
|
)
|
Net income (loss)
|
$
|
(177,568
|
)
|
|
$
|
50,388
|
|
|
$
|
42,234
|
|
|
$
|
(102,055
|
)
|
Basic net income (loss) per common share
|
$
|
(1.58
|
)
|
|
$
|
0.45
|
|
|
$
|
0.37
|
|
|
$
|
(0.90
|
)
|
Diluted net income (loss) per common share
|
$
|
(1.58
|
)
|
|
$
|
0.45
|
|
|
$
|
0.37
|
|
|
$
|
(0.90
|
)
|
Dividends declared per common share
|
$
|
0.05
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2018 (2)
|
|
|
|
|
|
|
|
||||||||
Total operating revenues and other income
|
$
|
769,595
|
|
|
$
|
443,916
|
|
|
$
|
459,369
|
|
|
$
|
394,192
|
|
Total operating expenses
|
310,527
|
|
|
387,768
|
|
|
568,013
|
|
|
(35,573
|
)
|
||||
Income (loss) from operations
|
$
|
459,068
|
|
|
$
|
56,148
|
|
|
$
|
(108,644
|
)
|
|
$
|
429,765
|
|
Income (loss) before income taxes
|
$
|
416,392
|
|
|
$
|
16,296
|
|
|
$
|
(172,671
|
)
|
|
$
|
391,760
|
|
Net income (loss)
|
$
|
317,401
|
|
|
$
|
17,197
|
|
|
$
|
(135,923
|
)
|
|
$
|
309,732
|
|
Basic net income (loss) per common share
|
$
|
2.84
|
|
|
$
|
0.15
|
|
|
$
|
(1.21
|
)
|
|
$
|
2.76
|
|
Diluted net income (loss) per common share
|
$
|
2.81
|
|
|
$
|
0.15
|
|
|
$
|
(1.21
|
)
|
|
$
|
2.73
|
|
Dividends declared per common share
|
$
|
0.05
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
(1)
|
Results of operations during 2019 were primarily impacted by the following:
|
(2)
|
For the first quarter of 2018, the Company recorded an estimated $409.2 million net pre-tax gain on divestiture activity related to the PRB Divestiture, which was partially offset by a $24.1 million write-down on certain assets. During the second quarter of 2018, the Company recorded an estimated $15.7 million net pre-tax gain on divestiture activity related to the Divide County Divestiture and Halff East Divestiture (please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions). During the third quarter of 2018, the Company recorded a $26.7 million loss on the early extinguishment of its 2021 Senior Notes, 2023 Senior Notes, and a portion of its 2022 Senior Notes (please refer to Note 5 – Long-Term Debt). For the first, second, third, and fourth quarters of 2018, the Company recorded net derivative losses of $7.5 million, $63.7 million, $178.0 million, and a net derivative gain of $411.1 million. Please refer to Note 10 – Derivative Financial Instruments for greater detail.
|
(i)
|
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
|
(ii)
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
|
(iii)
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements.
|
(1)
|
In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of the Company or any affiliate of the Company. The Company’s Board of Directors approved amendments to the Equity Plan in 2009, 2010, 2013, 2016, and 2018 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The number of shares of the Company’s common stock underlying awards granted in 2019, 2018, and 2017 under the Equity Plan were 1,868,776, 1,220,217, and 2,078,878, respectively.
|
(2)
|
RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per unit fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per unit fair value for the outstanding RSUs and PSUs was $16.04 and $16.89, respectively. Please refer to Note 7 – Compensation Plans in Part II, Item 8 of this report for additional discussion.
|
(3)
|
The number of awards to be issued assumes a one multiplier. The final number of shares of the Company’s common stock issued upon settlement may vary depending on the three-year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two.
|
(4)
|
Under the ESPP, eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the common stock is 85 percent of the lower of the fair market value of the common stock on the first or last day of the six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The number of shares of the Company’s common stock issued in 2019, 2018, and 2017 under the ESPP were 314,868, 199,464, and 186,665, respectively.
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Exhibit
Number
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Description
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101.INS
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Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
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101.SCH*
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Inline XBRL Schema Document
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101.CAL*
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Inline XBRL Calculation Linkbase Document
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101.LAB*
|
Inline XBRL Label Linkbase Document
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101.PRE*
|
Inline XBRL Presentation Linkbase Document
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101.DEF*
|
Inline XBRL Taxonomy Extension Definition Linkbase Document
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104
|
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)
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***
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Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Exchange Act.
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†
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Exhibit constitutes a management contract or compensatory plan or agreement.
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††
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Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document.
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+
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Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on
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SM ENERGY COMPANY
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(Registrant)
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Date:
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February 20, 2020
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By:
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/s/ JAVAN D. OTTOSON
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Javan D. Ottoson
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President and Chief Executive Officer
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(Principal Executive Officer)
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Signature
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Title
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Date
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/s/ JAVAN D. OTTOSON
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President, Chief Executive Officer, and Director
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February 20, 2020
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Javan D. Ottoson
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(Principal Executive Officer)
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/s/ A. WADE PURSELL
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Executive Vice President and Chief Financial Officer
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February 20, 2020
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A. Wade Pursell
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(Principal Financial Officer)
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/s/ PATRICK A. LYTLE
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Controller and Assistant Secretary
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February 20, 2020
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Patrick A. Lytle
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(Principal Accounting Officer)
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Signature
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Title
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Date
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/s/ WILLIAM D. SULLIVAN
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Chairman of the Board of Directors
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February 20, 2020
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William D. Sullivan
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/s/ CARLA J. BAILO
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Director
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February 20, 2020
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Carla J. Bailo
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/s/ LARRY W. BICKLE
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Director
|
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February 20, 2020
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Larry W. Bickle
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/s/ STEPHEN R. BRAND
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Director
|
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February 20, 2020
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Stephen R. Brand
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/s/ LOREN M. LEIKER
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Director
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February 20, 2020
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Loren M. Leiker
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/s/ RAMIRO G. PERU
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Director
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February 20, 2020
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Ramiro G. Peru
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/s/ JULIO M. QUINTANA
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Director
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February 20, 2020
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Julio M. Quintana
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/s/ ROSE M. ROBESON
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Director
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February 20, 2020
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Rose M. Robeson
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•
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Audit Committee - $20,000
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•
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Compensation Committee - $15,000
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•
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Nominating and Corporate Governance Committee - $10,000
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A.
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Wholly-owned subsidiaries of SM Energy Company, a Delaware corporation:
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1.
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SMT Texas LLC, a Colorado limited liability company
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2.
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Belring GP LLC, a Delaware limited liability company
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3.
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St. Mary Energy Louisiana LLC, a Delaware limited liability company
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4.
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Hilltop Investments, a Colorado general partnership
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5.
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Parish Ventures, a Colorado general partnership
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6.
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Green Canyon Offshore LLC, a Delaware limited liability company
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B.
|
Partnership or limited liability company interests held by SM Energy Company:
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1.
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Potato Creek Midstream, LLC, a Pennsylvania limited liability company (70%)
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2.
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1977 H.B Joint Account, a Colorado general partnership (8%)
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3.
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1976 H.B Joint Account, a Colorado general partnership (9%)
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4.
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1974 H.B Joint Account, a Colorado general partnership (4%)
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C.
|
Partnership interests held by SMT Texas, LLC:
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1.
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St. Mary Land East Texas LP, a Texas limited partnership (99%) (the remaining 1% interest is held by SM Energy Company)
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(1)
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Post-Effective Amendment No. 1 to Registration Statement (Form S-8 Nos. 333-30055, 333-106438, 333-35352, and 333-88780) of SM Energy Company,
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(2)
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Registration Statement (Form S-8 Nos. 333-58273, 333-134221, 333-151779, 333-165740, 333-170351, 333-194305, 333-212359, 333-219719, and 333-226660) of SM Energy Company,
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(3)
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Post-Effective Amendment No. 1 to Registration Statement (Form S-3 No. 333-203936 and 333-226597) of SM Energy Company, and
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(4)
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Registration Statement (Form S-3 No. 333-216843) of SM Energy Company;
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1.
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I have reviewed this annual report on Form 10-K of SM Energy Company;
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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;
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3.
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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;
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4.
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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;
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(b)
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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;
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(c)
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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
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(d)
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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
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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 annual report on Form 10-K 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/ Michael F. Stell
|
|
/s/ Val Rick Robinson
|
Michael F. Stell, P.E.
|
|
Val Rick Robinson
|
TBPE License No. 56416
|
|
TBPE License No. 105137
|
Advising Senior Vice President
|
|
Managing Senior Vice President
|
|
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
|
|
||
|
As of December 31, 2019
|
|
|
Proved
|
||||||
|
|
Developed
|
|
|
|
Total
|
||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
Net Reserves of Properties
Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBBL
|
|
76,295
|
|
3,804
|
|
76,781
|
|
156,880
|
Plant Products - MBBL
|
|
42,884
|
|
115
|
|
12,471
|
|
55,470
|
Gas – MMCF
|
|
687,964
|
|
9,697
|
|
321,346
|
|
1,019,007
|
|
|
|
|
|
|
|
|
|
Net Reserves of Properties
Not Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBBL
|
|
3,588
|
|
1,277
|
|
22,342
|
|
27,207
|
Plant Products - MBBL
|
|
253
|
|
156
|
|
18,135
|
|
18,544
|
Gas – MMCF
|
|
10,928
|
|
3,467
|
|
189,772
|
|
204,167
|
|
|
|
|
|
|
|
|
|
Total Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBBL
|
|
79,883
|
|
5,081
|
|
99,123
|
|
184,087
|
Plant Products - MBBL
|
|
43,137
|
|
271
|
|
30,606
|
|
74,014
|
Gas – MMCF
|
|
698,892
|
|
13,164
|
|
511,118
|
|
1,223,174
|
|
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
|
|
|
|
|
|
/s/ Michael F. Stell
|
|
Michael F. Stell, P.E.
|
|
|
TBPE License No. 56416
|
|
|
Advising Senior Vice President
|
|
|
|
|
|
|
/s/ Val Rick Robinson
|
|
|
Val Rick Robinson
|
|
|
TBPE License No. 105137
|
|
|
Managing Senior Vice President
|
(1)
|
completion intervals that are open at the time of the estimate but which have not yet started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|