Delaware
(State or other jurisdiction
of incorporation or organization)
|
41-0518430
(I.R.S. Employer Identification No.)
|
1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
|
80203
(Zip Code)
|
Title of each class
|
|
Name of each exchange on which registered
|
Common stock, $.01 par value
|
|
New York Stock Exchange
|
Large accelerated filer
þ
|
Accelerated filer
o
|
Non-accelerated filer
o
(Do not check if a smaller reporting company)
|
Smaller reporting company
o
|
|
||
TABLE OF CONTENTS
|
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ITEM
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PAGE
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TABLE OF CONTENTS
|
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(Continued)
|
||
ITEM
|
|
PAGE
|
|
||
|
||
•
|
Acquisition Activity.
During 2016, we acquired approximately
62,000
net acres in the Midland Basin in Howard and Martin Counties, Texas with producing and prospective intervals in the Lower and Middle Spraberry and Wolfcamp A and B shale formations and
15.0
MMBOE of existing proved reserves. We acquired these properties for total consideration of approximately
$2.6 billion
, which included
$2.2 billion
in cash and the issuance of
13.4 million
shares of our common stock.
|
•
|
Divestiture Activity
. During
2016
, we divested a total of
47.7
MMBOE of proved reserves in multiple transactions for total net cash proceeds of approximately
$946.1 million
. Our most significant divestiture was the sale of our Williston Basin assets outside of Divide County, North Dakota (referred to as “Raven/Bear Den” throughout this report) in the fourth quarter of 2016.
|
•
|
Reserves and Capital Investment.
Our estimated proved reserves
decreased
16 percent
to
395.8
MMBOE at
December 31, 2016
, from
471.3
MMBOE at
December 31, 2015
, of which
47.7
MMBOE related to the divestiture of proved reserves, as discussed above. We had strong reserve additions of
108.2
MMBOE as a result of our success in reducing costs, optimizing and enhancing completions, and generating better well results. These successes were offset by negative reserve revisions due to lower commodity prices and the removal of certain longer term proved undeveloped reserves that reflects our shift to develop our predominately unproven Midland Basin properties. Costs incurred for development and exploration activities, excluding acquisitions,
decreased
48 percent
to
$713.6 million
in
2016
when compared with
2015
. Our proved reserve life index
decreased
slightly to
7.2
years in
2016
. Please refer to
Reserves
and
Core Operational Areas
below for additional discussion.
|
•
|
Liquidity
. During 2016, we issued
$500.0 million
in aggregate principal amount of
6.75%
Senior Notes due
September 15, 2026
, at par, for net proceeds of
$491.6 million
. Additionally, we issued
$172.5 million
in aggregate principal amount of
1.50%
Senior Convertible Notes due
July 1, 2021
, for net proceeds of
$166.6 million
. During 2016, we also repurchased a total of
$46.3 million
in aggregate principal amount of a portion of our Senior Notes in open market transactions and paid down the entire
$202.0 million
outstanding balance on our
|
•
|
Equity Market Activities.
During 2016, we issued approximately
29.3 million
shares of our common stock in two public equity offerings and received
$934.1 million
in net proceeds. These issuances were in addition to the approximate
13.4 million
shares of our common stock issued as partial consideration for certain acquired properties as discussed above.
|
•
|
Production.
Our average daily production in 2016 consisted of
45.4
MBbl of oil,
401.5
MMcf of gas, and
38.8
MBbl of NGLs, for an average equivalent production rate of
151.0
MBOE per day, which represents a
14 percent
decrease on an equivalent basis compared with
2015
. This decrease in production was driven by our reduced drilling and completion activity and divestiture of assets. Please refer to
Core Operational Areas
below for additional discussion.
|
•
|
Impairments.
We recorded impairments of proved and unproved properties totaling
$435.0 million
for the year ended
December 31, 2016
. These impairments were largely due to the continued decline in commodity prices in early 2016 impacting our outside-operated Eagle Ford shale assets and negative performance revisions on our Powder River Basin assets at year-end 2016.
|
•
|
demonstrate the value of our 2016 acquisitions in the Midland Basin;
|
•
|
generate high margin production growth from our operated acreage positions in the Midland Basin and Eagle Ford shale;
|
•
|
successfully execute the sale of our outside-operated Eagle Ford shale and Divide County assets; and
|
•
|
reduce our outstanding debt.
|
|
South Texas & Gulf Coast
|
|
Permian
|
|
Rocky
Mountain
|
|
Total
(1)
|
||||||||
Proved Reserves
|
|
|
|
|
|
|
|
||||||||
Oil (MMBbl)
|
35.4
|
|
|
37.9
|
|
|
31.6
|
|
|
104.9
|
|
||||
Gas (Bcf)
|
989.3
|
|
|
94.6
|
|
|
27.2
|
|
|
1,111.1
|
|
||||
NGLs (MMBbl)
|
105.2
|
|
|
0.1
|
|
|
0.5
|
|
|
105.7
|
|
||||
MMBOE
(1)(2)
|
305.4
|
|
|
53.8
|
|
|
36.5
|
|
|
395.8
|
|
||||
Relative percentage
|
77
|
%
|
|
14
|
%
|
|
9
|
%
|
|
100
|
%
|
||||
Proved Developed %
|
55
|
%
|
|
40
|
%
|
|
53
|
%
|
|
53
|
%
|
||||
Production
|
|
|
|
|
|
|
|
||||||||
Oil (MMBbl)
|
5.5
|
|
|
2.7
|
|
|
8.3
|
|
|
16.6
|
|
||||
Gas (Bcf)
|
130.9
|
|
|
6.0
|
|
|
10.0
|
|
|
146.9
|
|
||||
NGLs (MMBbl)
|
13.9
|
|
|
—
|
|
|
0.3
|
|
|
14.2
|
|
||||
MMBOE
(1)(2)
|
41.2
|
|
|
3.8
|
|
|
10.3
|
|
|
55.3
|
|
||||
Avg. Daily Equivalents (MBOE/d)
(1)
|
112.6
|
|
|
10.2
|
|
|
28.2
|
|
|
151.0
|
|
||||
Relative percentage
|
74
|
%
|
|
7
|
%
|
|
19
|
%
|
|
100
|
%
|
||||
Costs Incurred (in millions)
(3)
|
$
|
254.6
|
|
|
$
|
2,874.1
|
|
|
$
|
226.0
|
|
|
$
|
3,373.9
|
|
(1)
|
Totals may not sum or calculate due to rounding.
|
(2)
|
As of December 31, 2016, our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 74.0 MMBOE of our proved reserves as of December 31, 2016, and approximately 9.7 MMBOE of 2016 production on an equivalent basis. Additionally, subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets.
|
(3)
|
Amounts do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activity that is excluded from the regional table above. Please refer to the caption
Costs Incurred in Oil and Gas Producing Activities
in the
Supplemental Oil and Gas Information
section in Part II, Item 8 of this report.
|
|
As of December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Reserve data:
|
|
|
|
|
|
||||||
Proved developed
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
48.5
|
|
|
75.6
|
|
|
89.3
|
|
|||
Gas (Bcf)
|
609.1
|
|
|
644.4
|
|
|
784.6
|
|
|||
NGLs (MMBbl)
|
58.6
|
|
|
61.5
|
|
|
66.7
|
|
|||
MMBOE
(1)
|
208.7
|
|
|
244.5
|
|
|
286.8
|
|
|||
Proved undeveloped
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
56.4
|
|
|
69.6
|
|
|
80.4
|
|
|||
Gas (Bcf)
|
502.0
|
|
|
619.7
|
|
|
682.0
|
|
|||
NGLs (MMBbl)
|
47.1
|
|
|
53.9
|
|
|
66.8
|
|
|||
MMBOE
(1)
|
187.1
|
|
|
226.8
|
|
|
260.9
|
|
|||
Total proved
(1)
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
104.9
|
|
|
145.3
|
|
|
169.7
|
|
|||
Gas (Bcf)
(2)
|
1,111.1
|
|
|
1,264.0
|
|
|
1,466.5
|
|
|||
NGLs (MMBbl)
|
105.7
|
|
|
115.4
|
|
|
133.5
|
|
|||
MMBOE
(1)(3)
|
395.8
|
|
|
471.3
|
|
|
547.7
|
|
|||
Proved developed reserves %
|
53
|
%
|
|
52
|
%
|
|
52
|
%
|
|||
Proved undeveloped reserves %
|
47
|
%
|
|
48
|
%
|
|
48
|
%
|
|||
|
|
|
|
|
|
||||||
Reserve data (in millions):
|
|
|
|
|
|
||||||
Standardized measure of discounted future net cash flows (GAAP)
|
$
|
1,152.1
|
|
|
$
|
1,790.5
|
|
|
$
|
5,698.8
|
|
PV-10 (non-GAAP):
|
|
|
|
|
|
||||||
Proved developed PV-10
|
$
|
1,051.1
|
|
|
$
|
1,593.0
|
|
|
$
|
5,253.0
|
|
Proved undeveloped PV-10
|
101.0
|
|
|
197.5
|
|
|
2,363.9
|
|
|||
Total proved PV-10
|
$
|
1,152.1
|
|
|
$
|
1,790.5
|
|
|
$
|
7,616.9
|
|
|
|
|
|
|
|
||||||
Reserve life index (years)
|
7.2
|
|
|
7.3
|
|
|
9.9
|
|
(1)
|
Totals may not sum or calculate due to rounding.
|
(2)
|
For the years ended December 31, 2016, and 2015, proved gas reserves contained 43.7 Bcf and 48.1 Bcf of gas, respectively, that we expect to produce and use as field fuel (primarily for compressors).
|
(3)
|
As of December 31, 2016, our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 74.0 MMBOE of our estimated proved reserves as of December 31, 2016. Additionally, subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets.
|
|
As of December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Standardized measure of discounted future net cash flows (GAAP)
|
$
|
1,152.1
|
|
|
$
|
1,790.5
|
|
|
$
|
5,698.8
|
|
Add: 10 percent annual discount, net of income taxes
|
937.1
|
|
|
1,307.1
|
|
|
3,407.2
|
|
|||
Add: future undiscounted income taxes
|
—
|
|
|
—
|
|
|
3,511.4
|
|
|||
Undiscounted future net cash flows
|
2,089.2
|
|
|
3,097.6
|
|
|
12,617.4
|
|
|||
Less: 10 percent annual discount without tax effect
|
(937.1
|
)
|
|
(1,307.1
|
)
|
|
(5,000.5
|
)
|
|||
PV-10 (non-GAAP)
|
$
|
1,152.1
|
|
|
$
|
1,790.5
|
|
|
$
|
7,616.9
|
|
|
Total
(MMBOE)
|
|
Total proved undeveloped reserves:
|
|
|
Beginning of year
|
226.8
|
|
Revisions of previous estimates
(1)
|
(34.3
|
)
|
Additions from discoveries, extensions, and infill
(2)
|
89.4
|
|
Sales of reserves
|
(17.1
|
)
|
Purchases of minerals in place
(3)
|
8.1
|
|
Removed for five-year rule
(4)
|
(43.0
|
)
|
Conversions to proved developed
(5)
|
(42.8
|
)
|
End of year
(6)
|
187.1
|
|
(1)
|
Revisions of previous estimates relate to a negative price revision of 25.5 MMBOE due to the decline in commodity prices during 2016 and a negative performance revision of 8.8 MMBOE.
|
(2)
|
We added 78.4 MMBOE of infill proved undeveloped reserves and an additional
11.0
MMBOE of proved undeveloped reserves through extensions and discoveries primarily in our Eagle Ford shale program.
|
(3)
|
We acquired
8.1
MMBOE of proved undeveloped reserves primarily in the Midland Basin. As of December 31, 2016, a relatively small portion of our future development capital was allocated to proved reserve locations. The remainder of capital allocated was to delineate our extensive acquired Midland Basin acreage position, still classified as unproven. We expect reserve growth over time as additional acreage is classified as proven and capital is allocated to offset locations.
|
(4)
|
Proved undeveloped reserves were reduced by
43.0
MMBOE due to changes in our development plan, which caused these locations to be reclassified primarily to the probable reserves category due to the five-year rule. These locations were replaced by higher quality proved undeveloped reserves, which are classified as extensions or infills in the table above, and resulted from our testing and delineation programs.
|
(5)
|
Conversions of proved undeveloped reserves to proved developed reserves were primarily in our Eagle Ford shale and Bakken/Three Forks programs. Our 2016 track record was slightly below 20 percent due to fewer conversions of proved undeveloped reserves in our Raven/Bear Den program, which we sold during the fourth quarter of 2016, and in our outside-operated Eagle Ford shale program due to the operator curtailing activity in 2016. Our 2016 development pace and our multi-year historical track record were both in excess of 20 percent. During
2016
, we incurred approximately
$268 million
on projects associated with reserves booked as proved undeveloped reserves at the end of
2015
, of which approximately
$226 million
was spent on proved undeveloped reserves converted to proved developed reserves by December 31, 2016. At December 31, 2016, drilled but not completed wells represented 28.0 MMBOE of total proved undeveloped reserves. We expect to incur approximately $145 million of capital expenditures in completing these wells, and we expect all of these wells to be completed within five years from their initial booking as proved undeveloped reserves.
|
(6)
|
As of December 31, 2016, none of our proved undeveloped reserves were on acreage expected to expire before their targeted completion date.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Net production
(2)
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
16.6
|
|
|
19.2
|
|
|
16.7
|
|
|||
Gas (Bcf)
|
146.9
|
|
|
173.6
|
|
|
152.9
|
|
|||
NGLs (MMBbl)
|
14.2
|
|
|
16.1
|
|
|
13.0
|
|
|||
MMBOE
(3)
|
55.3
|
|
|
64.2
|
|
|
55.1
|
|
|||
Eagle Ford net production
(1)(2)
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
5.4
|
|
|
7.6
|
|
|
6.9
|
|
|||
Gas (Bcf)
|
129.9
|
|
|
147.2
|
|
|
120.6
|
|
|||
NGLs (MMBbl)
|
13.8
|
|
|
15.6
|
|
|
12.7
|
|
|||
MMBOE
(3)
|
40.9
|
|
|
47.7
|
|
|
39.7
|
|
|||
Realized price, before the effect of derivative settlements
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
36.85
|
|
|
$
|
41.49
|
|
|
$
|
80.97
|
|
Gas (per Mcf)
|
$
|
2.30
|
|
|
$
|
2.57
|
|
|
$
|
4.58
|
|
NGLs (per Bbl)
|
$
|
16.16
|
|
|
$
|
15.92
|
|
|
$
|
33.34
|
|
Per BOE
|
$
|
21.32
|
|
|
$
|
23.36
|
|
|
$
|
45.01
|
|
Production costs per BOE
|
|
|
|
|
|
||||||
Lease operating expense
|
$
|
3.51
|
|
|
$
|
3.73
|
|
|
$
|
4.28
|
|
Transportation costs
|
$
|
6.16
|
|
|
$
|
6.02
|
|
|
$
|
6.11
|
|
Production taxes
|
$
|
0.94
|
|
|
$
|
1.13
|
|
|
$
|
2.13
|
|
Ad valorem tax expense
|
$
|
0.21
|
|
|
$
|
0.39
|
|
|
$
|
0.46
|
|
(1)
|
In each of the years
2016
,
2015
, and
2014
, total estimated proved reserves attributed to our Eagle Ford shale properties exceeded 15 percent of our total proved reserves expressed on an equivalent basis.
|
(2)
|
As of December 31, 2016, our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 9.7 MMBOE of production on an equivalent basis for the year ended December 31, 2016.
|
(3)
|
Amounts may not calculate due to rounding.
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil
|
100
|
|
|
73.0
|
|
|
87
|
|
|
56.5
|
|
|
133
|
|
|
66.1
|
|
Gas
|
114
|
|
|
56.1
|
|
|
272
|
|
|
100.8
|
|
|
476
|
|
|
165.5
|
|
Non-productive
|
2
|
|
|
1.1
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
5.3
|
|
|
216
|
|
|
130.2
|
|
|
359
|
|
|
157.3
|
|
|
617
|
|
|
236.9
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil
|
7
|
|
|
6.8
|
|
|
5
|
|
|
3.5
|
|
|
5
|
|
|
3.0
|
|
Gas
|
—
|
|
|
—
|
|
|
1
|
|
|
1.0
|
|
|
7
|
|
|
4.8
|
|
Non-productive
|
—
|
|
|
—
|
|
|
5
|
|
|
4.1
|
|
|
4
|
|
|
3.3
|
|
|
7
|
|
|
6.8
|
|
|
11
|
|
|
8.6
|
|
|
16
|
|
|
11.1
|
|
Total
|
223
|
|
|
137.0
|
|
|
370
|
|
|
165.9
|
|
|
633
|
|
|
248.0
|
|
|
As of January 31, 2017
|
||||
|
Gross
|
|
Net
|
||
Drilling:
(2)
|
|
|
|
||
Operated
|
9
|
|
|
8.9
|
|
Outside-operated
|
24
|
|
|
5.0
|
|
Total
|
33
|
|
|
13.9
|
|
|
|
|
|
||
Drilled but not completed:
(1) (2)
|
|
|
|
||
Operated
|
81
|
|
|
77.7
|
|
Outside-operated
|
133
|
|
|
24.8
|
|
Total
|
214
|
|
|
102.5
|
|
(1)
|
Represents wells that were being completed or waiting on completion as of January 31, 2017.
|
(2)
|
Subsequent to December 31, 2016, we executed a definitive sales agreement for our outside-operated Eagle Ford shale assets and announced our plans to sell our remaining Williston Basin assets in Divide County, North Dakota in 2017. As of January 31, 2017, we were participating in the drilling of 22 gross (4 net) outside-operated wells related to these assets. The drilled but not completed wells presented above include 20 gross (17 net) operated wells and 132 gross (24 net) outside-operated wells related to these assets.
|
|
Developed Acres
(1)
|
|
Undeveloped Acres
(2)(3)
|
|
Total
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
South Texas & Gulf Coast:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operated Eagle Ford
|
69,777
|
|
|
67,960
|
|
|
97,175
|
|
|
93,525
|
|
|
166,952
|
|
|
161,485
|
|
Outside-operated Eagle Ford
(5)
|
139,383
|
|
|
24,893
|
|
|
89,900
|
|
|
10,929
|
|
|
229,283
|
|
|
35,822
|
|
Other
|
5,780
|
|
|
869
|
|
|
7,783
|
|
|
5,771
|
|
|
13,563
|
|
|
6,640
|
|
Permian:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
RockStar
(4)
|
32,641
|
|
|
26,632
|
|
|
48,419
|
|
|
35,338
|
|
|
81,060
|
|
|
61,970
|
|
Sweetie Peck
|
15,020
|
|
|
14,409
|
|
|
361
|
|
|
192
|
|
|
15,381
|
|
|
14,601
|
|
Halff East
|
9,080
|
|
|
5,468
|
|
|
1,490
|
|
|
516
|
|
|
10,570
|
|
|
5,984
|
|
Rocky Mountain:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
North Rockies:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Divide
(6)
|
165,510
|
|
|
110,625
|
|
|
24,283
|
|
|
12,943
|
|
|
189,793
|
|
|
123,568
|
|
Other
(7)
|
—
|
|
|
—
|
|
|
244,371
|
|
|
172,148
|
|
|
244,371
|
|
|
172,148
|
|
South Rockies:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
PRB Cretaceous
|
50,429
|
|
|
38,625
|
|
|
141,116
|
|
|
117,637
|
|
|
191,545
|
|
|
156,262
|
|
Other
(7)
|
1,316
|
|
|
987
|
|
|
103,921
|
|
|
85,126
|
|
|
105,237
|
|
|
86,113
|
|
Other
(8)
|
10,499
|
|
|
10,499
|
|
|
18,891
|
|
|
16,232
|
|
|
29,390
|
|
|
26,731
|
|
Total
|
499,435
|
|
|
300,967
|
|
|
777,710
|
|
|
550,357
|
|
|
1,277,145
|
|
|
851,324
|
|
(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 presentation 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 the filing date of this report, approximately
35,900
,
20,200
, and
7,900
net acres of undeveloped acreage are scheduled to expire by
December 31, 2017
,
2018
, and
2019
, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases.
|
(4)
|
Refers to our recently acquired Midland Basin acreage in Howard and Martin Counties, Texas.
|
(5)
|
Our outside-operated Eagle Ford shale assets were held for sale as of December 31, 2016. Subsequent to year-end 2016, we entered into a definitive agreement with an expected closing date in the first quarter of 2017.
|
(6)
|
Subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets.
|
(7)
|
Includes other non-core acreage located in North Dakota, Montana, Wyoming, and Utah.
|
(8)
|
Includes Louisiana fee and other non-core acreage.
|
|
For the Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Major customer
(1)
|
18
|
%
|
|
21
|
%
|
|
19
|
%
|
Group #1 of entities under common ownership
(2)
|
15
|
%
|
|
10
|
%
|
|
14
|
%
|
Group #2 of entities under common ownership
(2)
|
8
|
%
|
|
11
|
%
|
|
9
|
%
|
(1)
|
This major customer is our operator in our outside-operated Eagle Ford shale program, which we entered into various marketing agreements with during 2013, whereby we are subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because we share with our operator the risk of non-performance by its counterparty purchasers, we have included our operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasers of our production from other areas. As of December 31, 2016, our outside-operated Eagle Ford shale assets were classified as held for sale.
|
(2)
|
In the aggregate, these groups of entities under common ownership represent more than
10 percent
of total production revenue for the period(s) shown; however, none of the entities comprising either group individually represented more than
10 percent
of our production revenue.
|
Region
|
|
Approximate Square Footage Leased
|
|
Corporate
|
|
108,000
|
|
Permian
|
|
54,000
|
|
South Texas & Gulf Coast
|
|
64,000
|
|
Rocky Mountain
(1)
|
|
—
|
|
Mid-Continent
(2)
|
|
50,000
|
|
Total
|
|
276,000
|
|
(1)
|
During the fourth quarter of 2016, we closed our office in Billings, Montana, and we executed an agreement to terminate the lease effective
November 11, 2016
. Please refer to
Note 14 - Exit and Disposal Costs
in Part II, Item 8 for additional discussion.
|
(2)
|
During the third quarter of 2015, we closed our office in Tulsa, Oklahoma. We have subleased this space through
2019
and our lease expires in 2022. Please refer to
Note 14 - Exit and Disposal Costs
in Part II, Item 8 for additional discussion.
|
•
|
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 natural 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.
|
•
|
the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
|
•
|
our outlook on future oil, gas, and NGL prices, well costs, and service costs;
|
•
|
the drilling of wells and other exploration and development activities and plans, as well as possible or expected acquisitions or divestitures;
|
•
|
the possible divestiture or farm-down of, or joint venture relating to, certain properties;
|
•
|
proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;
|
•
|
future oil, gas, and NGL production estimates;
|
•
|
cash flows, anticipated liquidity, and the future repayment of debt;
|
•
|
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and
|
•
|
other similar matters such as those discussed in the
Management’s Discussion and Analysis of Financial Condition and Results of Operations
section in Part II, Item 7 of this Form 10-K.
|
•
|
the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;
|
•
|
weakness in economic conditions and uncertainty in financial markets;
|
•
|
our ability to replace reserves in order to sustain production;
|
•
|
our ability to raise the substantial amount of capital required to develop and/or replace our reserves;
|
•
|
our ability to compete against competitors that have greater financial, technical, and human resources;
|
•
|
our ability to attract and retain key personnel;
|
•
|
the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;
|
•
|
the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;
|
•
|
the possibility that exploration and development drilling may not result in commercially producible reserves;
|
•
|
our limited control over activities on outside-operated properties;
|
•
|
our reliance on the skill and expertise of third-party service providers on our operated properties;
|
•
|
the possibility that title to properties in which we claim an interest may be defective;
|
•
|
our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;
|
•
|
the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;
|
•
|
the uncertainties associated with enhanced recovery methods;
|
•
|
our commodity derivative contracts may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;
|
•
|
the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;
|
•
|
our ability to deliver required quantities of crude oil, natural gas, natural gas liquids, or water to contractual counterparties;
|
•
|
price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
|
•
|
the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;
|
•
|
the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;
|
•
|
the possibility that covenants in our Credit Agreement or the indentures governing the Senior Notes and Senior Convertible Notes may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions or lead to the accelerated payment of our debt;
|
•
|
operating and environmental risks and hazards that could result in substantial losses;
|
•
|
the impact of seasonal weather conditions and lease stipulations on our ability to conduct drilling activities;
|
•
|
our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;
|
•
|
complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;
|
•
|
the availability and capacity of gathering, transportation, processing, and/or refining facilities;
|
•
|
our ability to sell and/or receive market prices for our oil, gas, and NGLs;
|
•
|
new technologies may cause our current exploration and drilling methods to become obsolete;
|
•
|
the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and
|
•
|
litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.
|
•
|
global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole;
|
•
|
the level of consumer demand for crude oil, natural 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 that may affect the realized prices for crude oil, natural gas, or NGLs;
|
•
|
liquefied natural gas deliveries to and from the United States;
|
•
|
the price and level of imports and exports of crude oil, refined petroleum products, and liquefied natural gas;
|
•
|
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 agree to and maintain crude oil price and production controls;
|
•
|
political instability or armed conflict in crude oil or natural gas producing regions;
|
•
|
strengthening and weakening of the United States dollar relative to other currencies; and
|
•
|
governmental regulations and taxes.
|
•
|
crude oil, natural gas, and NGL prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, leading to lower revenues, which could affect our financial condition and results of operations;
|
•
|
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 to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our 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 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 crude oil, natural gas, and NGLs;
|
•
|
curtailments or increases in consumption by oil purchasers and natural 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.
|
•
|
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 capital stock;
|
•
|
sell assets, including capital 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 another company.
|
•
|
the elimination of current deductions for intangible drilling and development costs;
|
•
|
the repeal of the percentage depletion allowance for oil and natural gas properties;
|
•
|
the elimination of the deduction for certain domestic production activities; and
|
•
|
an extension of the amortization period for certain geological and geophysical expenditures.
|
•
|
changes in crude oil, natural gas, or NGL prices;
|
•
|
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;
|
•
|
future sales of our common stock; and
|
•
|
changes in the national and global economic outlook.
|
ITEM 5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
Quarter Ended
|
|
High
|
|
Low
|
||||
December 31, 2016
|
|
$
|
43.09
|
|
|
$
|
30.25
|
|
September 30, 2016
|
|
$
|
40.39
|
|
|
$
|
23.58
|
|
June 30, 2016
|
|
$
|
35.60
|
|
|
$
|
17.04
|
|
March 31, 2016
|
|
$
|
20.65
|
|
|
$
|
6.99
|
|
|
|
|
|
|
||||
December 31, 2015
|
|
$
|
42.23
|
|
|
$
|
18.06
|
|
September 30, 2015
|
|
$
|
45.98
|
|
|
$
|
18.21
|
|
June 30, 2015
|
|
$
|
60.28
|
|
|
$
|
43.70
|
|
March 31, 2015
|
|
$
|
53.31
|
|
|
$
|
31.01
|
|
ISSUER PURCHASES OF EQUITY SECURITIES
|
||||||||||||
|
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)
|
|||||
January 1, 2016 -
March 31, 2016
|
176
|
|
|
$
|
14.87
|
|
|
—
|
|
|
3,072,184
|
|
April 1, 2016 -
June 30, 2016
|
1,053
|
|
|
$
|
28.99
|
|
|
—
|
|
|
3,072,184
|
|
July 1, 2016 -
September 30, 2016
|
85,418
|
|
|
$
|
27.02
|
|
|
—
|
|
|
3,072,184
|
|
October 1, 2016 -
October 31, 2016
|
343
|
|
|
$
|
39.37
|
|
|
—
|
|
|
3,072,184
|
|
November 1, 2016 -
November 30, 2016
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
December 1, 2016 -
December 31, 2016
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
Total October 1, 2016 -
December 31, 2016
|
343
|
|
|
$
|
39.37
|
|
|
—
|
|
|
3,072,184
|
|
Total
|
86,990
|
|
|
$
|
27.07
|
|
|
—
|
|
|
3,072,184
|
|
(1)
|
All shares purchased by us in
2016
offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under the Equity Incentive Compensation Plan (“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 date of this filing, 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 flow, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time. Please refer to
Dividends
above for a description of our dividend limitations.
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in millions, except per share data)
|
||||||||||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total operating revenues and other income
|
$
|
1,217.5
|
|
|
$
|
1,557.0
|
|
|
$
|
2,522.3
|
|
|
$
|
2,293.4
|
|
|
$
|
1,505.1
|
|
Net income (loss)
|
$
|
(757.7
|
)
|
|
$
|
(447.7
|
)
|
|
$
|
666.1
|
|
|
$
|
170.9
|
|
|
$
|
(54.2
|
)
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
|
$
|
9.91
|
|
|
$
|
2.57
|
|
|
$
|
(0.83
|
)
|
Diluted
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
|
$
|
9.79
|
|
|
$
|
2.51
|
|
|
$
|
(0.83
|
)
|
Balance Sheet Data (at end of period):
|
|
|
|
|
|
|
|
|
|||||||||||
Total assets
|
$
|
6,393.5
|
|
|
$
|
5,621.6
|
|
|
$
|
6,483.1
|
|
|
$
|
4,678.1
|
|
|
$
|
4,179.0
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revolving credit facility
|
$
|
—
|
|
|
$
|
202.0
|
|
|
$
|
166.0
|
|
|
$
|
—
|
|
|
$
|
340.0
|
|
Senior Notes, net of unamortized deferred financing costs
|
$
|
2,766.7
|
|
|
$
|
2,316.0
|
|
|
$
|
2,166.4
|
|
|
$
|
1,572.9
|
|
|
$
|
1,079.5
|
|
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
$
|
130.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Cash dividends declared and paid per common share
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
Supplemental Selected Financial and Operations Data
|
|||||||||||||||||||
|
|
||||||||||||||||||
|
For the Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Balance Sheet Data (in millions):
|
|
|
|
|
|
|
|
|
|||||||||||
Total working capital (deficit)
|
$
|
(190.5
|
)
|
|
$
|
216.5
|
|
|
$
|
(39.6
|
)
|
|
$
|
8.4
|
|
|
$
|
(201.0
|
)
|
Total stockholders’ equity
|
$
|
2,497.1
|
|
|
$
|
1,852.4
|
|
|
$
|
2,286.7
|
|
|
$
|
1,606.8
|
|
|
$
|
1,414.5
|
|
Weighted-average common shares outstanding (in thousands):
|
|
|
|
|
|
|
|||||||||||||
Basic
|
76,568
|
|
|
67,723
|
|
|
67,230
|
|
|
66,615
|
|
|
65,138
|
|
|||||
Diluted
|
76,568
|
|
|
67,723
|
|
|
68,044
|
|
|
67,998
|
|
|
65,138
|
|
|||||
Reserves:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
104.9
|
|
|
145.3
|
|
|
169.7
|
|
|
126.6
|
|
|
92.2
|
|
|||||
Gas (Bcf)
|
1,111.1
|
|
|
1,264.0
|
|
|
1,466.5
|
|
|
1,189.3
|
|
|
833.4
|
|
|||||
NGLs (MMBbl)
|
105.7
|
|
|
115.4
|
|
|
133.5
|
|
|
103.9
|
|
|
62.3
|
|
|||||
MMBOE
|
395.8
|
|
|
471.3
|
|
|
547.7
|
|
|
428.7
|
|
|
293.4
|
|
|||||
Production and Operations (in millions):
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil, gas, and NGL production revenue
|
$
|
1,178.4
|
|
|
$
|
1,499.9
|
|
|
$
|
2,481.5
|
|
|
$
|
2,199.6
|
|
|
$
|
1,473.9
|
|
Oil, gas, and NGL production expense
|
$
|
597.6
|
|
|
$
|
723.6
|
|
|
$
|
715.9
|
|
|
$
|
597.0
|
|
|
$
|
391.9
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
790.7
|
|
|
$
|
921.0
|
|
|
$
|
767.5
|
|
|
$
|
822.9
|
|
|
$
|
727.9
|
|
General and administrative
|
$
|
126.4
|
|
|
$
|
157.7
|
|
|
$
|
167.1
|
|
|
$
|
149.6
|
|
|
$
|
119.8
|
|
Production Volumes:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
16.6
|
|
|
19.2
|
|
|
16.7
|
|
|
13.9
|
|
|
10.4
|
|
|||||
Gas (Bcf)
|
146.9
|
|
|
173.6
|
|
|
152.9
|
|
|
149.3
|
|
|
120.0
|
|
|||||
NGLs (MMBbl)
|
14.2
|
|
|
16.1
|
|
|
13.0
|
|
|
9.5
|
|
|
6.1
|
|
|||||
MMBOE
|
55.3
|
|
|
64.2
|
|
|
55.1
|
|
|
48.3
|
|
|
36.5
|
|
|||||
Realized price, before the effect of derivative settlements:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
$
|
36.85
|
|
|
$
|
41.49
|
|
|
$
|
80.97
|
|
|
$
|
91.19
|
|
|
$
|
85.45
|
|
Gas (per Mcf)
|
$
|
2.30
|
|
|
$
|
2.57
|
|
|
$
|
4.58
|
|
|
$
|
3.93
|
|
|
$
|
2.98
|
|
NGLs (per Bbl)
|
$
|
16.16
|
|
|
$
|
15.92
|
|
|
$
|
33.34
|
|
|
$
|
35.95
|
|
|
$
|
37.61
|
|
Expense per BOE:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expense
|
$
|
3.51
|
|
|
$
|
3.73
|
|
|
$
|
4.28
|
|
|
$
|
4.49
|
|
|
$
|
4.54
|
|
Transportation costs
|
$
|
6.16
|
|
|
$
|
6.02
|
|
|
$
|
6.11
|
|
|
$
|
5.34
|
|
|
$
|
3.81
|
|
Production taxes
|
$
|
0.94
|
|
|
$
|
1.13
|
|
|
$
|
2.13
|
|
|
$
|
2.19
|
|
|
$
|
2.00
|
|
Ad valorem tax expense
|
$
|
0.21
|
|
|
$
|
0.39
|
|
|
$
|
0.46
|
|
|
$
|
0.33
|
|
|
$
|
0.39
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
14.30
|
|
|
$
|
14.34
|
|
|
$
|
13.92
|
|
|
$
|
17.02
|
|
|
$
|
19.95
|
|
General and administrative
|
$
|
2.29
|
|
|
$
|
2.46
|
|
|
$
|
3.03
|
|
|
$
|
3.09
|
|
|
$
|
3.28
|
|
Statement of Cash Flow Data (in millions):
|
|
|
|
|
|
|
|
|
|
||||||||||
Provided by operating activities
|
$
|
552.8
|
|
|
$
|
978.4
|
|
|
$
|
1,456.6
|
|
|
$
|
1,338.5
|
|
|
$
|
922.0
|
|
Used in investing activities
|
$
|
(1,870.6
|
)
|
|
$
|
(1,144.6
|
)
|
|
$
|
(2,478.7
|
)
|
|
$
|
(1,192.9
|
)
|
|
$
|
(1,457.3
|
)
|
Provided by financing activities
|
$
|
1,327.2
|
|
|
$
|
166.2
|
|
|
$
|
740.0
|
|
|
$
|
130.7
|
|
|
$
|
422.1
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Crude Oil (per Bbl):
|
|
|
|
|
|
||||||
Average NYMEX contract monthly price
|
$
|
43.32
|
|
|
$
|
48.68
|
|
|
$
|
93.03
|
|
Realized price, before the effect of derivative settlements
|
$
|
36.85
|
|
|
$
|
41.49
|
|
|
$
|
80.97
|
|
Effect of oil derivative settlements
|
$
|
14.63
|
|
|
$
|
18.85
|
|
|
$
|
1.71
|
|
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Average NYMEX monthly settle price (per MMBtu)
|
$
|
2.46
|
|
|
$
|
2.61
|
|
|
$
|
4.35
|
|
Realized price, before the effect of derivative settlements (per Mcf)
|
$
|
2.30
|
|
|
$
|
2.57
|
|
|
$
|
4.58
|
|
Effect of natural gas derivative settlements (per Mcf)
(1)
|
$
|
0.64
|
|
|
$
|
0.71
|
|
|
$
|
(0.18
|
)
|
|
|
|
|
|
|
||||||
NGLs (per Bbl):
|
|
|
|
|
|
||||||
Average OPIS price
(2)
|
$
|
19.98
|
|
|
$
|
19.76
|
|
|
$
|
38.93
|
|
Realized price, before the effect of derivative settlements
|
$
|
16.16
|
|
|
$
|
15.92
|
|
|
$
|
33.34
|
|
Effect of NGL derivative settlements
|
$
|
(0.60
|
)
|
|
$
|
1.69
|
|
|
$
|
0.84
|
|
(1)
|
Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include
$15.3 million
and
$5.6 million
, respectively, of early settlements of futures contracts as a result of divesting assets in our Mid-Continent region. These early settlements increased the effect of derivative settlements by
$0.09
per Mcf and
$0.04
per Mcf for the years ended December 31, 2015, and 2014, respectively.
|
(2)
|
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 15, 2017
|
|
As of December 31, 2016
|
||||
NYMEX WTI oil (per Bbl)
|
$
|
54.53
|
|
|
$
|
56.01
|
|
NYMEX Henry Hub gas (per MMBtu)
|
$
|
3.25
|
|
|
$
|
3.63
|
|
OPIS NGLs (per Bbl)
|
$
|
27.39
|
|
|
$
|
27.14
|
|
|
For the Year Ended
|
||
|
December 31, 2016
|
||
|
(in millions)
|
||
Development costs
|
$
|
595.3
|
|
Exploration costs
|
118.2
|
|
|
Acquisitions
|
|
||
Proved properties
|
201.7
|
|
|
Unproved properties
|
2,458.7
|
|
|
Total, including asset retirement obligation
(1)
|
$
|
3,373.9
|
|
(1)
|
Please refer to the section
Costs Incurred in Oil and Gas Producing Activities
in
Supplemental Oil and Gas Information
in Part II, Item 8 of this report.
|
•
|
On
October 4, 2016
, we closed our Rock Oil Acquisition in Howard County, Texas, for an adjusted purchase price of approximately
$991.0 million
, subject to customary post-closing adjustments.
|
•
|
On
December 21, 2016
, we closed our QStar Acquisition in Howard and Martin Counties, Texas, for an adjusted purchase price of approximately
$1.6 billion
, subject to customary post-closing adjustments.
|
•
|
On December 1, 2016, we completed our Raven/Bear Den asset divestiture for net divestiture proceeds of
$756.2 million
, subject to customary post-closing adjustments, as discussed in
Note 3 – Acquisitions, Divestitures, and Assets Held for Sale
in Part II, Item 8 of this report.
|
•
|
During the third quarter of 2016, we closed the divestitures of certain non-core properties in southeast New Mexico and in the Williston and Powder River Basins for total net divestiture proceeds of
$165.2 million
, subject to customary post-closing adjustments.
|
•
|
We began marketing our outside-operated Eagle Ford shale assets during the third quarter of 2016. Subsequent to December 31, 2016, we executed a definitive sales agreement for a gross purchase price of $800 million, subject to customary purchase price adjustments, with the sale expected to close in the first quarter of 2017.
|
•
|
Subsequent to December 31, 2016, we announced our plans to sell our remaining Williston Basin assets in Divide County, North Dakota.
|
•
|
On
August 12, 2016
, we issued approximately
18.4 million
shares of common stock in a public offering for net proceeds of
$530.9 million
.
|
•
|
On
December 7, 2016
, we issued an additional approximately
10.9 million
shares of common stock in a public offering for net proceeds of
$403.2 million
.
|
•
|
On
December 21, 2016
, to partially fund the QStar Acquisition, we issued to the sellers approximately
13.4 million
shares of common stock valued at
$437.2 million
.
|
•
|
Senior Convertible Notes
. On
August 12, 2016
, we issued
$172.5 million
in aggregate principal amount of 1.50% Senior Convertible Notes due 2021 for net proceeds of
$166.6 million
. In conjunction with this issuance, we paid
$24.2 million
for capped call transactions, which are generally expected to reduce the potential dilution and/or partially offset any cash payments required upon conversion.
|
•
|
2026 Notes
. On
September 12, 2016
, we issued
$500.0 million
in aggregate principal amount of
6.75%
Senior Notes due
2026
and received net proceeds of
$491.6 million
.
|
•
|
Repurchased Notes
. During the first quarter of 2016, we repurchased a total of
$46.3 million
in aggregate principal amount of certain of our Senior Notes in open market transactions for a settlement amount of
$29.9 million
, excluding interest, which resulted in a net gain on extinguishment of debt of approximately
$15.7 million
.
|
•
|
Credit Agreement
. Our borrowing base and aggregate lender commitments changed throughout 2016 due to the normal redetermination process, amendments to the Credit Agreement, and significant transactions that occurred. As of December 31, 2016, our borrowing base and aggregate lender commitments under the Credit Agreement were
$1.17 billion
.
|
|
Eagle Ford Shale
|
|
Midland Basin
|
|
Bakken/Three Forks
|
|
Total
|
||||||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||
Wells drilled but not completed at December 31, 2015
|
76
|
|
|
76
|
|
|
9
|
|
|
9
|
|
|
47
|
|
|
39
|
|
|
132
|
|
|
124
|
|
Wells drilled
|
16
|
|
|
16
|
|
|
27
|
|
|
25
|
|
|
24
|
|
|
23
|
|
|
67
|
|
|
64
|
|
Wells acquired
(1)
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
Wells completed
(2)
|
(45
|
)
|
|
(45
|
)
|
|
(30
|
)
|
|
(28
|
)
|
|
(51
|
)
|
|
(45
|
)
|
|
(126
|
)
|
|
(118
|
)
|
Wells drilled but not completed at December 31, 2016
(3)
|
47
|
|
|
47
|
|
|
17
|
|
|
17
|
|
|
20
|
|
|
17
|
|
|
84
|
|
|
81
|
|
(1)
|
Represents in-progress wells acquired in the Rock Oil and QStar acquisitions
.
In all cases, the sellers initiated the drilling of the well. Of these acquired in-progress wells, we completed six gross and net wells after the closing dates and before year-end 2016.
|
(2)
|
Of the wells we completed in 2016, 11 gross (eight net) wells were divested in the fourth quarter of 2016.
|
(3)
|
Subsequent to December 31, 2016, we announced plans to sell our remaining Bakken/Three Forks assets in Divide County, North Dakota.
|
|
South Texas & Gulf Coast
|
|
Permian
|
|
Rocky
Mountain
|
|
Total
(1)
|
||||
Production:
|
|
|
|
|
|
|
|
||||
Oil (MMBbl)
|
5.5
|
|
|
2.7
|
|
|
8.3
|
|
|
16.6
|
|
Gas (Bcf)
|
130.9
|
|
|
6.0
|
|
|
10.0
|
|
|
146.9
|
|
NGLs (MMBbl)
|
13.9
|
|
|
—
|
|
|
0.3
|
|
|
14.2
|
|
Equivalent (MMBOE)
(1)
|
41.2
|
|
|
3.8
|
|
|
10.3
|
|
|
55.3
|
|
Avg. Daily Equivalents (MBOE/d)
|
112.6
|
|
|
10.2
|
|
|
28.2
|
|
|
151.0
|
|
Relative percentage
|
74
|
%
|
|
7
|
%
|
|
19
|
%
|
|
100
|
%
|
(1)
|
Amounts may not calculate due to rounding.
|
•
|
We recorded a net loss of
$757.7 million
, or
$9.90
per diluted share, for the year ended
December 31, 2016
. This compares with a net loss of
$447.7 million
, or
$6.61
per diluted share, for the year ended
December 31, 2015
. The net loss in
2016
was driven largely by decreased production revenue due to sustained low commodity prices, discussed in detail above and a decrease in the fair value of commodity derivative contracts. Additionally, we recorded proved and unproved property impairments of
$354.6 million
and
$80.4 million
, respectively, for the year ended
December 31, 2016
. These impairments were largely due to the continued decline in commodity prices in early 2016 impacting our outside-operated Eagle Ford shale assets and negative reserve performance revisions on our Powder River Basin assets at year-end 2016. Please refer to the caption
Comparison of Financial Results and Trends Between
2016
and
2015
and Between
2015
and
2014
below for additional discussion regarding the components of net income (loss).
|
•
|
At year-end
2016
, we had estimated proved reserves of
395.8
MMBOE, of which
53 percent
were liquids (oil and NGLs) and
53 percent
were characterized as proved developed. During 2016, we added
108.2
MMBOE through our drilling program and acquired
15.5
MMBOE, as discussed above. We divested of
47.7
MMBOE of proved reserves and had negative revisions totaling
96.2
MMBOE, consisting of a negative
18.1
MMBOE performance revision, a negative
35.1
MMBOE price revision due to the decline in commodity prices in 2016, and
43.0
MMBOE of proved undeveloped reserves removed due to the five-year rule. Our proved reserve life index
decreased
slightly to
7.2
years in
2016
. Please refer to
Reserves
included in Part I, Items 1 and 2 of this report for additional discussion.
|
•
|
The standardized measure of discounted future net cash flows was
$1.2 billion
as of
December 31, 2016
, compared with
$1.8 billion
as of
December 31, 2015
. Please refer to the
Supplemental Oil and Gas Information
section located in Part II, Item 8 of this report.
|
•
|
We had net cash provided by operating activities of
$552.8 million
for the year ended
December 31, 2016
, compared with
$978.4 million
for the year ended
December 31, 2015
, which was a decrease of
43 percent
year-over-year. Please refer to
Analysis of Cash Flow Changes Between
2016
and
2015
and Between
2015
and
2014
below for additional discussion.
|
•
|
Adjusted EBITDAX, a non-GAAP financial measure, for the year ended
December 31, 2016
, was
$790.8 million
, compared with
$1.1 billion
for the same period in
2015
. Please refer to
Non-GAAP Financial Measures
below for additional discussion, including our definition of adjusted EBITDAX and a reconciliation of our net income (loss) and net cash provided by operating activities to adjusted EBITDAX.
|
•
|
demonstrate the value of our 2016 acquisitions in the Midland Basin;
|
•
|
generate high margin production growth from our operated acreage positions in the Midland Basin and Eagle Ford shale;
|
•
|
successfully execute the sale of our outside-operated Eagle Ford shale and Divide County assets; and
|
•
|
reduce our outstanding debt.
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2016
|
|
2016
|
|
2016
|
|
2016
|
||||||||
|
(in millions, except for production data)
|
||||||||||||||
Production (MMBOE)
|
13.4
|
|
|
14.2
|
|
|
14.3
|
|
|
13.4
|
|
||||
Oil, gas, and NGL production revenue
|
$
|
346.3
|
|
|
$
|
329.2
|
|
|
$
|
291.1
|
|
|
$
|
211.8
|
|
Oil, gas, and NGL production expense
|
$
|
151.9
|
|
|
$
|
152.5
|
|
|
$
|
148.6
|
|
|
$
|
144.5
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
171.6
|
|
|
$
|
194.0
|
|
|
$
|
211.0
|
|
|
$
|
214.2
|
|
Exploration
|
$
|
23.7
|
|
|
$
|
13.5
|
|
|
$
|
13.2
|
|
|
$
|
15.3
|
|
General and administrative
|
$
|
33.3
|
|
|
$
|
32.7
|
|
|
$
|
28.2
|
|
|
$
|
32.2
|
|
Net income (loss)
|
$
|
(200.9
|
)
|
|
$
|
(40.9
|
)
|
|
$
|
(168.7
|
)
|
|
$
|
(347.2
|
)
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2016
|
|
2016
|
|
2016
|
|
2016
|
||||||||
Average net daily production equivalent (MBOE per day)
|
145.6
|
|
|
153.9
|
|
|
157.2
|
|
|
147.5
|
|
||||
Lease operating expense (per BOE)
|
$
|
3.67
|
|
|
$
|
3.29
|
|
|
$
|
3.31
|
|
|
$
|
3.79
|
|
Transportation costs (per BOE)
|
$
|
6.39
|
|
|
$
|
6.24
|
|
|
$
|
5.95
|
|
|
$
|
6.06
|
|
Production taxes as a percent of oil, gas, and NGL production revenue
|
4.3
|
%
|
|
4.5
|
%
|
|
4.6
|
%
|
|
4.2
|
%
|
||||
Ad valorem tax expense (per BOE)
|
$
|
0.17
|
|
|
$
|
0.21
|
|
|
$
|
0.19
|
|
|
$
|
0.27
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
|
$
|
12.81
|
|
|
$
|
13.70
|
|
|
$
|
14.75
|
|
|
$
|
15.96
|
|
General and administrative (per BOE)
|
$
|
2.49
|
|
|
$
|
2.31
|
|
|
$
|
1.97
|
|
|
$
|
2.40
|
|
|
For the Years Ended December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016/2015
|
|
2015/2014
|
|
2016/2015
|
|
2015/2014
|
||||||||||||||
Net production volumes
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MMBbl)
|
16.6
|
|
|
19.2
|
|
|
16.7
|
|
|
(2.6
|
)
|
|
2.6
|
|
|
(14
|
)%
|
|
15
|
%
|
|||||||
Gas (Bcf)
|
146.9
|
|
|
173.6
|
|
|
152.9
|
|
|
(26.7
|
)
|
|
20.7
|
|
|
(15
|
)%
|
|
14
|
%
|
|||||||
NGLs (MMBbl)
|
14.2
|
|
|
16.1
|
|
|
13.0
|
|
|
(1.9
|
)
|
|
3.1
|
|
|
(12
|
)%
|
|
24
|
%
|
|||||||
Equivalent (MMBOE)
|
55.3
|
|
|
64.2
|
|
|
55.1
|
|
|
(8.9
|
)
|
|
9.1
|
|
|
(14
|
)%
|
|
16
|
%
|
|||||||
Average net daily production
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MBbl per day)
|
45.4
|
|
|
52.7
|
|
|
45.6
|
|
|
(7.3
|
)
|
|
7.0
|
|
|
(14
|
)%
|
|
15
|
%
|
|||||||
Gas (MMcf per day)
|
401.5
|
|
|
475.7
|
|
|
419.0
|
|
|
(74.2
|
)
|
|
56.7
|
|
|
(16
|
)%
|
|
14
|
%
|
|||||||
NGLs (MBbl per day)
|
38.8
|
|
|
44.0
|
|
|
35.6
|
|
|
(5.2
|
)
|
|
8.4
|
|
|
(12
|
)%
|
|
24
|
%
|
|||||||
Equivalent (MBOE per day)
|
151.0
|
|
|
175.9
|
|
|
151.1
|
|
|
(24.9
|
)
|
|
24.9
|
|
|
(14
|
)%
|
|
16
|
%
|
|||||||
Oil, gas, and NGL production revenue (in millions)
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Oil production revenue
|
$
|
611.8
|
|
|
$
|
797.3
|
|
|
$
|
1,348.3
|
|
|
$
|
(185.5
|
)
|
|
$
|
(551.0
|
)
|
|
(23
|
)%
|
|
(41
|
)%
|
||
Gas production revenue
|
337.3
|
|
|
447.0
|
|
|
699.8
|
|
|
(109.7
|
)
|
|
(252.8
|
)
|
|
(25
|
)%
|
|
(36
|
)%
|
|||||||
NGL production revenue
|
229.3
|
|
|
255.6
|
|
|
433.4
|
|
|
(26.3
|
)
|
|
(177.8
|
)
|
|
(10
|
)%
|
|
(41
|
)%
|
|||||||
Total
|
$
|
1,178.4
|
|
|
$
|
1,499.9
|
|
|
$
|
2,481.5
|
|
|
$
|
(321.5
|
)
|
|
$
|
(981.6
|
)
|
|
(21
|
)%
|
|
(40
|
)%
|
||
Oil, gas, and NGL production expense (in millions)
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Lease operating expense
|
$
|
194.0
|
|
|
$
|
239.6
|
|
|
$
|
235.8
|
|
|
$
|
(45.6
|
)
|
|
$
|
3.8
|
|
|
(19
|
)%
|
|
2
|
%
|
||
Transportation costs
|
340.3
|
|
|
386.6
|
|
|
337.1
|
|
|
(46.3
|
)
|
|
49.5
|
|
|
(12
|
)%
|
|
15
|
%
|
|||||||
Production taxes
|
51.9
|
|
|
72.4
|
|
|
117.2
|
|
|
(20.5
|
)
|
|
(44.8
|
)
|
|
(28
|
)%
|
|
(38
|
)%
|
|||||||
Ad valorem tax expense
|
11.4
|
|
|
25.0
|
|
|
25.8
|
|
|
(13.6
|
)
|
|
(0.8
|
)
|
|
(54
|
)%
|
|
(3
|
)%
|
|||||||
Total
|
$
|
597.6
|
|
|
$
|
723.6
|
|
|
$
|
715.9
|
|
|
$
|
(126.0
|
)
|
|
$
|
7.7
|
|
|
(17
|
)%
|
|
1
|
%
|
||
Realized price, before the effect of derivative settlements
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Oil (per Bbl)
|
$
|
36.85
|
|
|
$
|
41.49
|
|
|
$
|
80.97
|
|
|
$
|
(4.64
|
)
|
|
$
|
(39.48
|
)
|
|
(11
|
)%
|
|
(49
|
)%
|
||
Gas (per Mcf)
|
$
|
2.30
|
|
|
$
|
2.57
|
|
|
$
|
4.58
|
|
|
$
|
(0.27
|
)
|
|
$
|
(2.01
|
)
|
|
(11
|
)%
|
|
(44
|
)%
|
||
NGLs (per Bbl)
|
$
|
16.16
|
|
|
$
|
15.92
|
|
|
$
|
33.34
|
|
|
$
|
0.24
|
|
|
$
|
(17.42
|
)
|
|
2
|
%
|
|
(52
|
)%
|
||
Per BOE
|
$
|
21.32
|
|
|
$
|
23.36
|
|
|
$
|
45.01
|
|
|
$
|
(2.04
|
)
|
|
$
|
(21.65
|
)
|
|
(9
|
)%
|
|
(48
|
)%
|
||
Per BOE data
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expense
|
$
|
3.51
|
|
|
$
|
3.73
|
|
|
$
|
4.28
|
|
|
$
|
(0.22
|
)
|
|
$
|
(0.55
|
)
|
|
(6
|
)%
|
|
(13
|
)%
|
||
Transportation costs
|
$
|
6.16
|
|
|
$
|
6.02
|
|
|
$
|
6.11
|
|
|
$
|
0.14
|
|
|
$
|
(0.09
|
)
|
|
2
|
%
|
|
(1
|
)%
|
||
Production taxes
|
$
|
0.94
|
|
|
$
|
1.13
|
|
|
$
|
2.13
|
|
|
$
|
(0.19
|
)
|
|
$
|
(1.00
|
)
|
|
(17
|
)%
|
|
(47
|
)%
|
||
Ad valorem tax expense
|
$
|
0.21
|
|
|
$
|
0.39
|
|
|
$
|
0.46
|
|
|
$
|
(0.18
|
)
|
|
$
|
(0.07
|
)
|
|
(46
|
)%
|
|
(15
|
)%
|
||
General and administrative
|
$
|
2.29
|
|
|
$
|
2.46
|
|
|
$
|
3.03
|
|
|
$
|
(0.17
|
)
|
|
$
|
(0.57
|
)
|
|
(7
|
)%
|
|
(19
|
)%
|
||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
14.30
|
|
|
$
|
14.34
|
|
|
$
|
13.92
|
|
|
$
|
(0.04
|
)
|
|
$
|
0.42
|
|
|
—
|
%
|
|
3
|
%
|
||
Derivative settlement gain
(2)
|
$
|
5.96
|
|
|
$
|
7.98
|
|
|
$
|
0.22
|
|
|
$
|
(2.02
|
)
|
|
$
|
7.76
|
|
|
(25
|
)%
|
|
3,527
|
%
|
||
Earnings per share information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Basic net income (loss) per common share
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
|
$
|
9.91
|
|
|
$
|
(3.29
|
)
|
|
$
|
(16.52
|
)
|
|
50
|
%
|
|
(167
|
)%
|
||
Diluted net income (loss) per common share
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
|
$
|
9.79
|
|
|
$
|
(3.29
|
)
|
|
$
|
(16.40
|
)
|
|
50
|
%
|
|
(168
|
)%
|
||
Basic weighted-average common shares outstanding (in thousands)
|
76,568
|
|
|
67,723
|
|
|
67,230
|
|
|
8,845
|
|
|
493
|
|
|
13
|
%
|
|
1
|
%
|
|||||||
Diluted weighted-average common shares outstanding (in thousands)
|
76,568
|
|
|
67,723
|
|
|
68,044
|
|
|
8,845
|
|
|
(321
|
)
|
|
13
|
%
|
|
—
|
%
|
(1)
|
Amounts and percentage changes may not calculate due to rounding.
|
(2)
|
Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include
$15.3 million
and
$5.6 million
, respectively, of early settlements of futures contracts as a result of divesting assets in our Mid-Continent region. These early settlements increased the effect of derivative settlements by
$0.24
and
$0.10
per BOE for the years ended December 31, 2015, and 2014, respectively.
|
|
Average Net Daily Production Increase (Decrease)
|
|
Production Revenue Increase (Decrease)
|
|
Production Costs Decrease
|
|||||
|
(MBOE/d)
|
|
(in millions)
|
|
(in millions)
|
|||||
South Texas & Gulf Coast
|
(20.3
|
)
|
|
$
|
(240.8
|
)
|
|
$
|
(93.6
|
)
|
Rocky Mountain
|
(2.9
|
)
|
|
(90.7
|
)
|
|
(19.6
|
)
|
||
Permian
|
2.9
|
|
|
35.9
|
|
|
(0.6
|
)
|
||
Mid-Continent
(1)
|
(4.6
|
)
|
|
(25.9
|
)
|
|
(12.2
|
)
|
||
Total
|
(24.9
|
)
|
|
$
|
(321.5
|
)
|
|
$
|
(126.0
|
)
|
(1)
|
We divested our Mid-Continent assets in the second quarter of 2015.
|
|
Average Net Daily Production Increase (Decrease)
|
|
Production Revenue Decrease
|
|
Production Costs Increase (Decrease)
|
|||||
|
(MBOE/d)
|
|
(in millions)
|
|
(in millions)
|
|||||
South Texas & Gulf Coast
|
22.8
|
|
|
$
|
(587.8
|
)
|
|
$
|
54.0
|
|
Rocky Mountain
|
7.2
|
|
|
(230.5
|
)
|
|
(8.2
|
)
|
||
Permian
|
(0.2
|
)
|
|
(98.8
|
)
|
|
(16.6
|
)
|
||
Mid-Continent
(1)
|
(4.9
|
)
|
|
(64.5
|
)
|
|
(21.5
|
)
|
||
Total
|
24.9
|
|
|
$
|
(981.6
|
)
|
|
$
|
7.7
|
|
(1)
|
We divested our Mid-Continent assets in the second quarter of 2015.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Net gain on divestiture activity
|
$
|
37.1
|
|
|
$
|
43.0
|
|
|
$
|
0.6
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Marketed gas system revenue
|
$
|
—
|
|
|
$
|
9.5
|
|
|
$
|
24.9
|
|
Marketed gas system expense
|
$
|
—
|
|
|
$
|
13.9
|
|
|
$
|
24.5
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Other operating revenues
|
$
|
2.0
|
|
|
$
|
4.5
|
|
|
$
|
15.2
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Oil, gas, and NGL production expense
|
$
|
597.6
|
|
|
$
|
723.6
|
|
|
$
|
715.9
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
790.7
|
|
|
$
|
921.0
|
|
|
$
|
767.5
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Geological and geophysical expenses
|
$
|
11.0
|
|
|
$
|
7.5
|
|
|
$
|
11.4
|
|
Exploratory dry hole
|
—
|
|
|
36.6
|
|
|
44.4
|
|
|||
Overhead and other expenses
|
54.6
|
|
|
76.5
|
|
|
74.1
|
|
|||
Total
|
$
|
65.6
|
|
|
$
|
120.6
|
|
|
$
|
129.9
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Impairment of proved properties
|
$
|
354.6
|
|
|
$
|
468.7
|
|
|
$
|
84.5
|
|
Abandonment and impairment of unproved properties
|
$
|
80.4
|
|
|
$
|
78.6
|
|
|
$
|
75.6
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Impairment of other property and equipment
|
$
|
—
|
|
|
$
|
49.4
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
General and administrative
|
$
|
126.4
|
|
|
$
|
157.7
|
|
|
$
|
167.1
|
|
Exit and disposal costs
(1)
|
$
|
5.1
|
|
|
$
|
9.3
|
|
|
$
|
—
|
|
(1)
|
Exit and disposal costs are recorded in general and administrative expense in the accompanying statements of operations.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Change in Net Profits Plan liability
|
$
|
(7.2
|
)
|
|
$
|
(19.5
|
)
|
|
$
|
(29.8
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Net derivative (gain) loss
|
$
|
250.6
|
|
|
$
|
(408.8
|
)
|
|
$
|
(583.3
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Other operating expenses
|
$
|
18.0
|
|
|
$
|
30.6
|
|
|
$
|
4.7
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Gain (loss) on extinguishment of debt
|
$
|
15.7
|
|
|
$
|
(16.6
|
)
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Interest expense
|
$
|
(158.7
|
)
|
|
$
|
(128.1
|
)
|
|
$
|
(98.6
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions, except tax rate)
|
||||||||||
Income tax (expense) benefit
|
$
|
444.2
|
|
|
$
|
275.2
|
|
|
$
|
(398.6
|
)
|
Effective tax rate
|
37.0
|
%
|
|
38.1
|
%
|
|
37.4
|
%
|
|
For the Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Weighted-average interest rate
|
6.2
|
%
|
|
6.0
|
%
|
|
6.5
|
%
|
Weighted-average borrowing rate
|
5.7
|
%
|
|
5.5
|
%
|
|
5.9
|
%
|
|
|
For the Years Ended
December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2016/2015
|
|
2015/2014
|
|
2016/2015
|
|
2015/2014
|
||||||||||||
|
|
(in millions)
|
|
|
|
|
||||||||||||||||||||
Net cash provided by operating activities
|
|
$
|
552.8
|
|
|
$
|
978.4
|
|
|
$
|
1,456.6
|
|
|
$
|
(425.6
|
)
|
|
$
|
(478.2
|
)
|
|
(43
|
)%
|
|
(33
|
)%
|
|
|
For the Years Ended
December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2016/2015
|
|
2015/2014
|
|
2016/2015
|
|
2015/2014
|
||||||||||||
|
|
(in millions)
|
|
|
|
|
||||||||||||||||||||
Net cash used in investing activities
|
|
$
|
(1,870.6
|
)
|
|
$
|
(1,144.6
|
)
|
|
$
|
(2,478.7
|
)
|
|
$
|
(726.0
|
)
|
|
$
|
1,334.1
|
|
|
63
|
%
|
|
(54
|
)%
|
|
|
For the Years Ended
December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2016/2015
|
|
2015/2014
|
|
2016/2015
|
|
2015/2014
|
||||||||||||
|
|
(in millions)
|
|
|
|
|
||||||||||||||||||||
Net cash provided by financing activities
|
|
$
|
1,327.2
|
|
|
$
|
166.2
|
|
|
$
|
740.0
|
|
|
$
|
1,161.0
|
|
|
$
|
(573.8
|
)
|
|
699
|
%
|
|
(78
|
)%
|
Contractual Obligations
|
|
Total
|
|
Less than 1 year
|
|
1-3 years
|
|
3-5 years
|
|
More than 5 years
|
||||||||||
Long-term debt
(1)
|
|
$
|
2,976.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
519.4
|
|
|
$
|
2,456.8
|
|
Interest payments
(2)
|
|
1,275.8
|
|
|
174.3
|
|
|
351.2
|
|
|
347.6
|
|
|
402.7
|
|
|||||
Delivery commitments
(3)
|
|
970.9
|
|
|
105.7
|
|
|
274.9
|
|
|
269.0
|
|
|
321.3
|
|
|||||
Operating leases and contracts
(3)
|
|
87.2
|
|
|
39.4
|
|
|
17.7
|
|
|
13.7
|
|
|
16.4
|
|
|||||
Asset retirement obligations
(4)
|
|
161.2
|
|
|
6.8
|
|
|
34.8
|
|
|
2.2
|
|
|
117.4
|
|
|||||
Derivative liability
(5)
|
|
214.4
|
|
|
115.6
|
|
|
97.4
|
|
|
1.4
|
|
|
—
|
|
|||||
Other
(6)
|
|
38.4
|
|
|
7.9
|
|
|
15.6
|
|
|
14.9
|
|
|
—
|
|
|||||
Total
|
|
$
|
5,724.1
|
|
|
$
|
449.7
|
|
|
$
|
791.6
|
|
|
$
|
1,168.2
|
|
|
$
|
3,314.6
|
|
(1)
|
Long-term debt consists of our Senior Notes and Senior Convertible Notes, and assumes no principal repayment until the due dates of the instruments. The actual payments may vary significantly. As of December 31, 2016, we had a zero balance on our revolving credit facility.
|
(2)
|
Interest payments on our Senior Notes and Senior Convertible Notes are estimated assuming no principal repayment until the due dates of the instruments. As our credit facility balance was zero at December 31, 2016, the above table reflects only the fee that would be paid on the unused credit facility’s aggregate lender commitment amount through the maturity date of the Credit Agreement. The actual interest payments on our Senior Notes, Senior Convertible Notes, and 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. The amount relating to our gathering, processing, and transportation throughput commitments in the table above reflects the aggregate undiscounted deficiency payments assuming we delivered no product. Subsequent to
December 31, 2016
, we entered into a definitive agreement for the sale of our outside-operated Eagle Ford shale assets held for sale at
December 31, 2016
, and expect to close the transaction in the first quarter of 2017, at which point we would no longer be subject to throughput commitments totaling
$501.9 million
of the deficiency payments presented in the table above.
|
(4)
|
Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on our accompanying consolidated balance sheets as of
December 31, 2016
. 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. Obligations related to inactive wells or wells that are not economic at current commodity price levels as of
December 31, 2016
, are shown as an obligation in 1-3 years due to the substantial uncertainty on the timing of plugging or re-entering these wells. Please refer to
Note 9 – 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, 2016
, 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
$37.9 million
, for which we have estimated the timing of future payments based on historical annual contribution amounts.
|
|
For the Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
|
MMBOE
|
|
MMBOE
|
|
MMBOE
|
|||
|
Change
|
|
Change
|
|
Change
|
|||
Revisions resulting from performance
|
(18.1
|
)
|
|
47.3
|
|
|
11.3
|
|
Removal of proved undeveloped reserves no longer in our five-year development plan
|
(43.0
|
)
|
|
(79.4
|
)
|
|
(4.3
|
)
|
Revisions resulting from price changes
|
(35.1
|
)
|
|
(116.5
|
)
|
|
3.4
|
|
Total
|
(96.2
|
)
|
|
(148.6
|
)
|
|
10.4
|
|
|
For the Year Ended
December 31, 2016
|
||||
|
MMBOE
|
|
Percentage
|
||
|
Change
|
|
Change
|
||
10 percent decrease in SEC pricing
(1)
|
(81
|
)
|
|
(21
|
)%
|
Average NYMEX strip pricing as of fiscal year end
(2)
|
163
|
|
|
41
|
%
|
10 percent decrease in proved undeveloped reserves
(3)
|
(19
|
)
|
|
(5
|
)%
|
(1)
|
The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported proved reserve volumes as of December 31, 2016, and does not include additional impacts to our proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.
|
(2)
|
The change reflects the impact of replacing SEC pricing with the calculated average of the five year NYMEX strip pricing for each product as of December 31, 2016. The five year average NYMEX strip prices used in the analysis were $56.19 per Bbl for oil, $3.09 per MMBtu for gas, and $27.44 per Bbl for NGL. Other impacts modeled in the analysis resulting from the hypothetical improved pricing include: 1) management’s estimate of escalation in future service and equipment costs at the commodity price level noted above 2) extension of economic lives and increase in economically recoverable volumes; 3) additional proved undeveloped reserve locations that pass the PV-0 hurdle; and 4) additional proved undeveloped reserve locations that could be reasonably drilled within five years given additional capital that would be available for development at the commodity price level noted above. We did not add any proved undeveloped reserve locations in our outside-operated Eagle Ford shale or Bakken/Three Forks program in Divide County, North Dakota given our intent to sell these properties in 2017.
|
(3)
|
The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2016, and does not include any additional impacts to our proved reserves.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
Net income (loss) (GAAP)
|
$
|
(757,744
|
)
|
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
|
|
Interest expense
|
158,685
|
|
|
128,149
|
|
|
98,554
|
|
|||
|
Other non-operating (income) expense, net
|
(362
|
)
|
|
(649
|
)
|
|
2,561
|
|
|||
|
Income tax expense (benefit)
|
(444,172
|
)
|
|
(275,151
|
)
|
|
398,648
|
|
|||
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
790,745
|
|
|
921,009
|
|
|
767,532
|
|
|||
|
Exploration
(1)
|
59,194
|
|
|
113,158
|
|
|
122,577
|
|
|||
|
Impairment of proved properties
|
354,614
|
|
|
468,679
|
|
|
84,480
|
|
|||
|
Abandonment and impairment of unproved properties
|
80,367
|
|
|
78,643
|
|
|
75,638
|
|
|||
|
Impairment of other property and equipment
|
—
|
|
|
49,369
|
|
|
—
|
|
|||
|
Stock-based compensation expense
|
26,897
|
|
|
27,467
|
|
|
32,694
|
|
|||
|
Net derivative (gain) loss
|
250,633
|
|
|
(408,831
|
)
|
|
(583,264
|
)
|
|||
|
Derivative settlement gain
(2)
|
329,478
|
|
|
512,566
|
|
|
12,615
|
|
|||
|
Change in Net Profits Plan liability
|
(7,200
|
)
|
|
(19,525
|
)
|
|
(29,849
|
)
|
|||
|
Net gain on divestiture activity
|
(37,074
|
)
|
|
(43,031
|
)
|
|
(646
|
)
|
|||
|
(Gain) loss on extinguishment of debt
|
(15,722
|
)
|
|
16,578
|
|
|
—
|
|
|||
|
Materials inventory impairment
|
2,436
|
|
|
4,054
|
|
|
—
|
|
|||
Adjusted EBITDAX (Non-GAAP)
|
790,775
|
|
|
1,124,775
|
|
|
1,647,591
|
|
||||
|
Interest expense
|
(158,685
|
)
|
|
(128,149
|
)
|
|
(98,554
|
)
|
|||
|
Other non-operating income (expense), net
|
362
|
|
|
649
|
|
|
(2,561
|
)
|
|||
|
Income tax (expense) benefit
|
444,172
|
|
|
275,151
|
|
|
(398,648
|
)
|
|||
|
Exploration
(1)
|
(59,194
|
)
|
|
(113,158
|
)
|
|
(122,577
|
)
|
|||
|
Exploratory dry hole expense
|
(16
|
)
|
|
36,612
|
|
|
44,427
|
|
|||
|
Amortization of discount and deferred financing costs
|
9,938
|
|
|
7,710
|
|
|
6,146
|
|
|||
|
Deferred income taxes
|
(448,643
|
)
|
|
(276,722
|
)
|
|
397,780
|
|
|||
|
Plugging and abandonment
|
(6,214
|
)
|
|
(7,496
|
)
|
|
(8,796
|
)
|
|||
|
Loss on extinguishment of debt
|
—
|
|
|
(12,455
|
)
|
|
—
|
|
|||
|
Other, net
|
1,063
|
|
|
9,707
|
|
|
1,069
|
|
|||
|
Changes in current assets and liabilities
|
(20,754
|
)
|
|
61,728
|
|
|
(9,302
|
)
|
|||
Net cash provided by operating activities (GAAP)
|
$
|
552,804
|
|
|
$
|
978,352
|
|
|
$
|
1,456,575
|
|
(1)
|
Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.
|
(2)
|
Derivative settlement gain for the years ended December 31, 2015, and 2014, includes
$15.3 million
and
$5.6 million
, respectively, of gains on the early settlement of futures contracts as a result of divesting our Mid-Continent assets.
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
9,372
|
|
|
$
|
18
|
|
Accounts receivable
|
151,950
|
|
|
134,124
|
|
||
Derivative asset
|
54,521
|
|
|
367,710
|
|
||
Prepaid expenses and other
|
8,799
|
|
|
17,137
|
|
||
Total current assets
|
224,642
|
|
|
518,989
|
|
||
|
|
|
|
||||
Property and equipment (successful efforts method):
|
|
|
|
||||
Proved oil and gas properties
|
5,700,418
|
|
|
7,606,405
|
|
||
Less - accumulated depletion, depreciation, and amortization
|
(2,836,532
|
)
|
|
(3,481,836
|
)
|
||
Unproved oil and gas properties
|
2,471,947
|
|
|
284,538
|
|
||
Wells in progress
|
235,147
|
|
|
387,432
|
|
||
Oil and gas properties held for sale, net
|
372,621
|
|
|
641
|
|
||
Other property and equipment, net of accumulated depreciation of $42,882 and $32,956, respectively
|
137,753
|
|
|
153,100
|
|
||
Total property and equipment, net
|
6,081,354
|
|
|
4,950,280
|
|
||
|
|
|
|
||||
Noncurrent assets:
|
|
|
|
||||
Derivative asset
|
67,575
|
|
|
120,701
|
|
||
Other noncurrent assets
|
19,940
|
|
|
31,673
|
|
||
Total other noncurrent assets
|
87,515
|
|
|
152,374
|
|
||
Total Assets
|
$
|
6,393,511
|
|
|
$
|
5,621,643
|
|
|
|
|
|
||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses
|
$
|
299,708
|
|
|
$
|
302,517
|
|
Derivative liability
|
115,464
|
|
|
8
|
|
||
Total current liabilities
|
415,172
|
|
|
302,525
|
|
||
|
|
|
|
||||
Noncurrent liabilities:
|
|
|
|
||||
Revolving credit facility
|
—
|
|
|
202,000
|
|
||
Senior Notes, net of unamortized deferred financing costs
|
2,766,719
|
|
|
2,315,970
|
|
||
Senior Convertible Notes, net of unamortized discount and deferred financing costs
|
130,856
|
|
|
—
|
|
||
Asset retirement obligation
|
96,134
|
|
|
137,284
|
|
||
Asset retirement obligation associated with oil and gas properties held for sale
|
26,241
|
|
|
241
|
|
||
Deferred income taxes
|
315,672
|
|
|
758,279
|
|
||
Derivative liability
|
98,340
|
|
|
—
|
|
||
Other noncurrent liabilities
|
47,244
|
|
|
52,943
|
|
||
Total noncurrent liabilities
|
3,481,206
|
|
|
3,466,717
|
|
||
|
|
|
|
||||
Commitments and contingencies (note 6)
|
|
|
|
||||
|
|
|
|
||||
Stockholders
’
equity:
|
|
|
|
||||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,257,500 and 68,075,700 shares, respectively
|
1,113
|
|
|
681
|
|
||
Additional paid-in capital
|
1,716,556
|
|
|
305,607
|
|
||
Retained earnings
|
794,020
|
|
|
1,559,515
|
|
||
Accumulated other comprehensive loss
|
(14,556
|
)
|
|
(13,402
|
)
|
||
Total stockholders
’
equity
|
2,497,133
|
|
|
1,852,401
|
|
||
Total Liabilities and Stockholders
’
Equity
|
$
|
6,393,511
|
|
|
$
|
5,621,643
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Operating revenues and other income:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production revenue
|
$
|
1,178,426
|
|
|
$
|
1,499,905
|
|
|
$
|
2,481,544
|
|
Net gain on divestiture activity
|
37,074
|
|
|
43,031
|
|
|
646
|
|
|||
Marketed gas system revenue
|
—
|
|
|
9,485
|
|
|
24,897
|
|
|||
Other operating revenues
|
1,950
|
|
|
4,544
|
|
|
15,220
|
|
|||
Total operating revenues and other income
|
1,217,450
|
|
|
1,556,965
|
|
|
2,522,307
|
|
|||
|
|
|
|
|
|
||||||
Operating expenses:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production expense
|
597,565
|
|
|
723,633
|
|
|
715,878
|
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
790,745
|
|
|
921,009
|
|
|
767,532
|
|
|||
Exploration
|
65,641
|
|
|
120,569
|
|
|
129,857
|
|
|||
Impairment of proved properties
|
354,614
|
|
|
468,679
|
|
|
84,480
|
|
|||
Abandonment and impairment of unproved properties
|
80,367
|
|
|
78,643
|
|
|
75,638
|
|
|||
Impairment of other property and equipment
|
—
|
|
|
49,369
|
|
|
—
|
|
|||
General and administrative
|
126,428
|
|
|
157,668
|
|
|
167,103
|
|
|||
Change in Net Profits Plan liability
|
(7,200
|
)
|
|
(19,525
|
)
|
|
(29,849
|
)
|
|||
Net derivative (gain) loss
|
250,633
|
|
|
(408,831
|
)
|
|
(583,264
|
)
|
|||
Marketed gas system expense
|
—
|
|
|
13,922
|
|
|
24,460
|
|
|||
Other operating expenses
|
17,972
|
|
|
30,612
|
|
|
4,658
|
|
|||
Total operating expenses
|
2,276,765
|
|
|
2,135,748
|
|
|
1,356,493
|
|
|||
|
|
|
|
|
|
||||||
Income (loss) from operations
|
(1,059,315
|
)
|
|
(578,783
|
)
|
|
1,165,814
|
|
|||
|
|
|
|
|
|
||||||
Non-operating income (expense):
|
|
|
|
|
|
||||||
Interest expense
|
(158,685
|
)
|
|
(128,149
|
)
|
|
(98,554
|
)
|
|||
Gain (loss) on extinguishment of debt
|
15,722
|
|
|
(16,578
|
)
|
|
—
|
|
|||
Other, net
|
362
|
|
|
649
|
|
|
(2,561
|
)
|
|||
|
|
|
|
|
|
||||||
Income (loss) before income taxes
|
(1,201,916
|
)
|
|
(722,861
|
)
|
|
1,064,699
|
|
|||
Income tax (expense) benefit
|
444,172
|
|
|
275,151
|
|
|
(398,648
|
)
|
|||
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(757,744
|
)
|
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
|
|
|
|
|
|
||||||
Basic weighted-average common shares outstanding
|
76,568
|
|
|
67,723
|
|
|
67,230
|
|
|||
Diluted weighted-average common shares outstanding
|
76,568
|
|
|
67,723
|
|
|
68,044
|
|
|||
Basic net income (loss) per common share
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
|
$
|
9.91
|
|
Diluted net income (loss) per common share
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
|
$
|
9.79
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Net income (loss)
|
$
|
(757,744
|
)
|
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
Other comprehensive loss, net of tax:
|
|
|
|
|
|
||||||
Pension liability adjustment
(1)
|
(1,154
|
)
|
|
(2,090
|
)
|
|
(5,896
|
)
|
|||
Total other comprehensive loss, net of tax
|
(1,154
|
)
|
|
(2,090
|
)
|
|
(5,896
|
)
|
|||
Total comprehensive income (loss)
|
$
|
(758,898
|
)
|
|
$
|
(449,800
|
)
|
|
$
|
660,155
|
|
(1)
|
Refer to
Note 1 - Summary of Significant Accounting Policies
for detail of the pension amount reclassified to general and administrative expense on the Company
’s
consolidated statements of operations.
|
|
|
|
Additional Paid-in Capital
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Loss
|
|
Total Stockholders’ Equity
|
||||||||||||||||
|
Common Stock
|
|
|
Treasury Stock
|
|
Retained Earnings
|
|
|
|||||||||||||||||||||
|
Shares
|
|
Amount
|
|
|
Shares
|
|
Amount
|
|
|
|
||||||||||||||||||
Balances, January 1, 2014
|
67,078,853
|
|
|
$
|
671
|
|
|
$
|
257,720
|
|
|
(22,412
|
)
|
|
$
|
(823
|
)
|
|
$
|
1,354,669
|
|
|
$
|
(5,416
|
)
|
|
$
|
1,606,821
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
666,051
|
|
|
—
|
|
|
666,051
|
|
||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,896
|
)
|
|
(5,896
|
)
|
||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,723
|
)
|
|
—
|
|
|
(6,723
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
83,136
|
|
|
1
|
|
|
4,060
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,061
|
|
||||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
|
256,718
|
|
|
3
|
|
|
(10,627
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,624
|
)
|
||||||
Issuance of common stock upon stock option exercises
|
39,088
|
|
|
—
|
|
|
816
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
816
|
|
||||||
Stock-based compensation expense
|
5,265
|
|
|
—
|
|
|
31,871
|
|
|
22,412
|
|
|
823
|
|
|
—
|
|
|
—
|
|
|
32,694
|
|
||||||
Other income tax expense
|
—
|
|
|
—
|
|
|
(545
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(545
|
)
|
||||||
Balances, December 31, 2014
|
67,463,060
|
|
|
$
|
675
|
|
|
$
|
283,295
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
2,013,997
|
|
|
$
|
(11,312
|
)
|
|
$
|
2,286,655
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(447,710
|
)
|
|
—
|
|
|
(447,710
|
)
|
||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,090
|
)
|
|
(2,090
|
)
|
||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,772
|
)
|
|
—
|
|
|
(6,772
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
197,214
|
|
|
2
|
|
|
4,842
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,844
|
|
||||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
|
375,523
|
|
|
4
|
|
|
(8,682
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,678
|
)
|
||||||
Stock-based compensation expense
|
39,903
|
|
|
—
|
|
|
27,467
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27,467
|
|
||||||
Other income tax expense
|
—
|
|
|
—
|
|
|
(1,315
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,315
|
)
|
||||||
Balances, December 31, 2015
|
68,075,700
|
|
|
$
|
681
|
|
|
$
|
305,607
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
1,559,515
|
|
|
$
|
(13,402
|
)
|
|
$
|
1,852,401
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(757,744
|
)
|
|
—
|
|
|
(757,744
|
)
|
||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,154
|
)
|
|
(1,154
|
)
|
||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,751
|
)
|
|
—
|
|
|
(7,751
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
218,135
|
|
|
2
|
|
|
4,196
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,198
|
|
||||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
|
199,243
|
|
|
2
|
|
|
(2,356
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,354
|
)
|
||||||
Stock-based compensation expense
|
53,473
|
|
|
1
|
|
|
26,896
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26,897
|
|
||||||
Issuance of common stock from stock offerings, net of tax
|
42,710,949
|
|
|
427
|
|
|
1,382,666
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,383,093
|
|
||||||
Equity component of 1.50% Senior Convertible Notes due 2021 issuance, net of tax
|
—
|
|
|
—
|
|
|
33,575
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33,575
|
|
||||||
Purchase of capped call transactions
|
—
|
|
|
—
|
|
|
(24,195
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(24,195
|
)
|
||||||
Other income tax expense
|
—
|
|
|
—
|
|
|
(9,833
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9,833
|
)
|
||||||
Balances, December 31, 2016
|
111,257,500
|
|
|
$
|
1,113
|
|
|
$
|
1,716,556
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
794,020
|
|
|
$
|
(14,556
|
)
|
|
$
|
2,497,133
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(757,744
|
)
|
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Net gain on divestiture activity
|
(37,074
|
)
|
|
(43,031
|
)
|
|
(646
|
)
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
790,745
|
|
|
921,009
|
|
|
767,532
|
|
|||
Exploratory dry hole expense
|
(16
|
)
|
|
36,612
|
|
|
44,427
|
|
|||
Impairment of proved properties
|
354,614
|
|
|
468,679
|
|
|
84,480
|
|
|||
Abandonment and impairment of unproved properties
|
80,367
|
|
|
78,643
|
|
|
75,638
|
|
|||
Impairment of other property and equipment
|
—
|
|
|
49,369
|
|
|
—
|
|
|||
Stock-based compensation expense
|
26,897
|
|
|
27,467
|
|
|
32,694
|
|
|||
Change in Net Profits Plan liability
|
(7,200
|
)
|
|
(19,525
|
)
|
|
(29,849
|
)
|
|||
Net derivative (gain) loss
|
250,633
|
|
|
(408,831
|
)
|
|
(583,264
|
)
|
|||
Derivative settlement gain
|
329,478
|
|
|
512,566
|
|
|
12,615
|
|
|||
Amortization of discount and deferred financing costs
|
9,938
|
|
|
7,710
|
|
|
6,146
|
|
|||
Non-cash (gain) loss on extinguishment of debt
|
(15,722
|
)
|
|
4,123
|
|
|
—
|
|
|||
Deferred income taxes
|
(448,643
|
)
|
|
(276,722
|
)
|
|
397,780
|
|
|||
Plugging and abandonment
|
(6,214
|
)
|
|
(7,496
|
)
|
|
(8,796
|
)
|
|||
Other, net
|
3,499
|
|
|
13,761
|
|
|
1,069
|
|
|||
Changes in current assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
(10,562
|
)
|
|
140,200
|
|
|
24,088
|
|
|||
Prepaid expenses and other
|
8,478
|
|
|
2,563
|
|
|
(1,822
|
)
|
|||
Accounts payable and accrued expenses
|
(53,210
|
)
|
|
(86,267
|
)
|
|
9,466
|
|
|||
Accrued derivative settlements
|
34,540
|
|
|
5,232
|
|
|
(41,034
|
)
|
|||
Net cash provided by operating activities
|
552,804
|
|
|
978,352
|
|
|
1,456,575
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Net proceeds from the sale of oil and gas properties
|
946,062
|
|
|
357,938
|
|
|
43,858
|
|
|||
Capital expenditures
|
(629,911
|
)
|
|
(1,493,608
|
)
|
|
(1,974,798
|
)
|
|||
Acquisition of proved and unproved oil and gas properties
|
(2,183,790
|
)
|
|
(7,984
|
)
|
|
(544,553
|
)
|
|||
Other, net
|
(3,000
|
)
|
|
(985
|
)
|
|
(3,256
|
)
|
|||
Net cash used in investing activities
|
(1,870,639
|
)
|
|
(1,144,639
|
)
|
|
(2,478,749
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from credit facility
|
947,000
|
|
|
1,872,500
|
|
|
1,285,500
|
|
|||
Repayment of credit facility
|
(1,149,000
|
)
|
|
(1,836,500
|
)
|
|
(1,119,500
|
)
|
|||
Debt issuance costs related to credit facility
|
(3,132
|
)
|
|
—
|
|
|
(3,388
|
)
|
|||
Net proceeds from Senior Notes
|
491,640
|
|
|
490,951
|
|
|
589,991
|
|
|||
Cash paid to repurchase Senior Notes
|
(29,904
|
)
|
|
(350,000
|
)
|
|
—
|
|
|||
Net proceeds from Senior Convertible Notes
|
166,617
|
|
|
—
|
|
|
—
|
|
|||
Cash paid for capped call transactions
|
(24,195
|
)
|
|
—
|
|
|
—
|
|
|||
Net proceeds from sale of common stock
|
938,268
|
|
|
4,844
|
|
|
4,877
|
|
|||
Dividends paid
|
(7,751
|
)
|
|
(6,772
|
)
|
|
(6,723
|
)
|
|||
Net share settlement from issuance of stock awards
|
(2,354
|
)
|
|
(8,678
|
)
|
|
(10,624
|
)
|
|||
Other, net
|
—
|
|
|
(160
|
)
|
|
(87
|
)
|
|||
Net cash provided by financing activities
|
1,327,189
|
|
|
166,185
|
|
|
740,046
|
|
|||
|
|
|
|
|
|
||||||
Net change in cash and cash equivalents
|
9,354
|
|
|
(102
|
)
|
|
(282,128
|
)
|
|||
Cash and cash equivalents at beginning of period
|
18
|
|
|
120
|
|
|
282,248
|
|
|||
Cash and cash equivalents at end of period
|
$
|
9,372
|
|
|
$
|
18
|
|
|
$
|
120
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Supplemental Cash Flow Information:
|
|
|
|
|
|
||||||
Operating activities:
|
|
|
|
|
|
||||||
Cash paid for interest, net of capitalized interest
|
$
|
129,761
|
|
|
$
|
126,988
|
|
|
$
|
89,145
|
|
Net cash (refunded) paid for income taxes
|
$
|
(4,690
|
)
|
|
$
|
1,630
|
|
|
$
|
1,936
|
|
Investing activities:
|
|
|
|
|
|
||||||
Changes in capital expenditure accruals and other
|
$
|
8,044
|
|
|
$
|
(210,819
|
)
|
|
$
|
130,143
|
|
|
|
|
|
|
|
||||||
Supplemental Non-Cash Investing Activities:
|
|
|
|
|
|
||||||
Fair value of properties exchanged
|
$
|
733
|
|
|
$
|
—
|
|
|
$
|
6,164
|
|
|
|
|
|
|
|
||||||
Supplemental Non-Cash Financing Activities:
|
|
|
|
|
|
||||||
Issuance of common stock for an asset acquisition
(1)
|
$
|
437,194
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Refer to
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
and
Note 15 - Equity
for additional discussion.
|
|
For the Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Major customer
(1)
|
18
|
%
|
|
21
|
%
|
|
19
|
%
|
Group #1 of entities under common ownership
(2)
|
15
|
%
|
|
10
|
%
|
|
14
|
%
|
Group #2 of entities under common ownership
(2)
|
8
|
%
|
|
11
|
%
|
|
9
|
%
|
(1)
|
This major customer is the operator of the Company’s outside-operated Eagle Ford shale program, in which the Company entered into various marketing agreements with during 2013, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because the Company shares with its operator the risk of non-performance by its counterparty purchasers, the Company has included its operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasers of the Company’s production from other areas. As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were classified as held for sale.
|
(2)
|
In the aggregate these groups of entities under common ownership represent more than 10 percent of total production revenue for the period(s) shown, however,
none
of the entities comprising either group individually represented more than 10 percent of the Company’s production revenue.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands, except per share amounts)
|
||||||||||
Net income (loss)
|
$
|
(757,744
|
)
|
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
Basic weighted-average common shares outstanding
|
76,568
|
|
|
67,723
|
|
|
67,230
|
|
|||
Add: dilutive effect of unvested RSUs, contingent PSUs, and stock options
(1)
|
—
|
|
|
—
|
|
|
814
|
|
|||
Add: dilutive effect of 1.50% Senior Convertible Notes
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Diluted weighted-average common shares outstanding
|
76,568
|
|
|
67,723
|
|
|
68,044
|
|
|||
Basic net income (loss) per common share
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
|
$
|
9.91
|
|
Diluted net income (loss) per common share
|
$
|
(9.90
|
)
|
|
$
|
(6.61
|
)
|
|
$
|
9.79
|
|
(1)
|
For the years ended
December 31, 2016
, and
2015
, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share.
|
(2)
|
For the year ended
December 31, 2016
, shares of the Company’s common stock traded at an average closing price below the
$40.50
conversion price, and therefore, had no dilutive impact and were excluded from the calculation of diluted earnings per share.
|
|
Pension Liability Adjustments
|
||
|
(in thousands)
|
||
For the year ended December 31, 2014
|
|
||
Net actuarial loss
|
$
|
(10,062
|
)
|
Reclassification to earnings
|
706
|
|
|
Tax benefit
|
3,460
|
|
|
Loss, net of tax
|
$
|
(5,896
|
)
|
For the year ended December 31, 2015
|
|
||
Net actuarial loss
|
$
|
(4,990
|
)
|
Reclassification to earnings
|
1,853
|
|
|
Tax benefit
|
1,047
|
|
|
Loss, net of tax
|
$
|
(2,090
|
)
|
For the year ended December 31, 2016
|
|
||
Net actuarial loss
|
$
|
(3,322
|
)
|
Reclassification to earnings
|
1,598
|
|
|
Tax benefit
|
570
|
|
|
Loss, net of tax
|
$
|
(1,154
|
)
|
•
|
In August 2015, the FASB issued ASU No. 2015-14,
Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date
. This ASU deferred the effective date of ASU 2014-09 by one year.
|
•
|
In March 2016, the FASB issued ASU No. 2016-08,
Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
. This ASU amends the principal versus agent guidance in ASU No. 2014-09.
|
•
|
In April 2016, the FASB issued ASU No. 2016-10,
Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing
. This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09.
|
•
|
In May 2016, the FASB issued ASU No. 2016-12,
Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients.
This ASU amends certain issues in ASU 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes.
|
•
|
In December 2016, the FASB issued ASU No. 2016-20,
Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers
. This ASU is meant to improve and clarify or to correct unintended application of narrow aspects of the guidance in ASU 2014-09.
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Accrued oil, gas, and NGL production revenue
|
$
|
96,101
|
|
|
$
|
58,256
|
|
Amounts due from joint interest owners
|
29,669
|
|
|
22,269
|
|
||
State severance tax refunds
|
15,320
|
|
|
12,072
|
|
||
Accrued derivative settlements
|
6,512
|
|
|
34,579
|
|
||
Other
|
4,348
|
|
|
6,948
|
|
||
Total accounts receivable
|
$
|
151,950
|
|
|
$
|
134,124
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Accrued capital expenditures
|
$
|
107,009
|
|
|
$
|
97,355
|
|
Revenue and severance tax payable
|
39,617
|
|
|
44,387
|
|
||
Accrued lease operating expense
|
15,956
|
|
|
21,943
|
|
||
Accrued property taxes
|
6,606
|
|
|
14,078
|
|
||
Accrued compensation
|
34,761
|
|
|
41,154
|
|
||
Accrued derivative settlements
|
6,473
|
|
|
—
|
|
||
Accrued interest
|
45,059
|
|
|
34,378
|
|
||
Other
|
44,227
|
|
|
49,222
|
|
||
Total accounts payable and accrued expenses
|
$
|
299,708
|
|
|
$
|
302,517
|
|
•
|
Rock Oil Acquisition.
On
October 4, 2016
, the Company acquired all membership interests of JPM EOC Opal, LLC, which owned proved and unproved properties in the Midland Basin, from Rock Oil Holdings, LLC (referred to as the “Rock Oil Acquisition”) for an adjusted purchase price of
$991.0 million
. The effective date of the acquisition was September 1, 2016. The Company funded the acquisition with proceeds from divestitures in 2016 and the Senior Convertible Notes and equity offerings in August 2016, as discussed in
Note 5 - Long-Term Debt
and
Note 15 - Equity
,
respectively.
|
|
As of October 4, 2016
|
||
|
(in thousands)
|
||
Cash consideration
|
$
|
991,038
|
|
|
|
||
Fair value of assets and liabilities acquired:
|
|
||
Wells in progress
|
$
|
5,672
|
|
Proved oil and gas properties
|
81,917
|
|
|
Unproved oil and gas properties
|
913,594
|
|
|
Other assets
|
5,338
|
|
|
Total fair value of oil and gas properties acquired
|
1,006,521
|
|
|
Working capital
|
(7,888
|
)
|
|
Asset retirement obligation
|
(7,595
|
)
|
|
Total fair value of net assets acquired
|
$
|
991,038
|
|
•
|
QStar Acquisition.
On
December 21, 2016
, the Company acquired additional proved and unproved properties in the Midland Basin from QStar LLC and RRP-QStar, LLC (referred to as the “QStar Acquisition”) for
$1.6 billion
, consisting of
$1.2 billion
in cash consideration and the issuance of approximately
13.4 million
shares of the Company’s common stock. The cash consideration was funded by proceeds from the recent Raven/Bear Den divestiture and the December 2016 equity offering. Please refer to
Note 15 - Equity
for additional discussion. The effective date of the acquisition was
September 1, 2016
. Under authoritative accounting guidance, the transaction was considered an asset acquisition, and therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired.
|
|
As of December 21, 2016
|
||
|
(in thousands)
|
||
Cash consideration, including acquisition costs paid
|
$
|
1,167,373
|
|
Fair value of equity consideration
(1)
|
437,194
|
|
|
Total consideration at closing
|
$
|
1,604,567
|
|
|
|
||
Assets and liabilities acquired:
|
|
||
Wells in progress
|
$
|
21,812
|
|
Proved oil and gas properties
|
61,614
|
|
|
Unproved oil and gas properties
|
1,537,923
|
|
|
Total oil and gas properties acquired
|
1,621,349
|
|
|
Working capital
|
(9,141
|
)
|
|
Asset retirement obligation
|
(7,641
|
)
|
|
Total net assets acquired
|
$
|
1,604,567
|
|
(1)
|
The Company issued approximately
13.4 million
shares of common stock, par value
$0.01
per share, in a private placement to the sellers in the QStar Acquisition on December 21, 2016. The equity consideration was valued on this date using Level 1 and Level 2 inputs with a discount applied due to the lack of marketability in the near term in accordance with the Lock-Up and Registration Rights Agreement that prohibits the sale of such stock until no earlier than the 90th day after issuance.
|
•
|
Other Acquisitions.
During the fourth quarter of 2016, the Company entered into a definitive purchase agreement to acquire approximately
2,900
net acres of oil and gas assets in the Midland Basin for a gross purchase price of
$60 million
, subject to customary purchase price adjustments. This acquisition closed subsequent to December 31, 2016.
|
•
|
Gooseneck Property Acquisitions
|
|
Acquisition #1
|
|
Acquisition #2
|
||||
|
As of September 24, 2014
|
|
As of October 15, 2014
|
||||
|
(in thousands)
|
||||||
Cash consideration
|
$
|
321,807
|
|
|
$
|
84,836
|
|
|
|
|
|
||||
Fair value of assets and liabilities acquired:
|
|
|
|
||||
Proved oil and gas properties
|
$
|
203,467
|
|
|
$
|
54,612
|
|
Unproved oil and gas properties
|
126,588
|
|
|
29,610
|
|
||
Total fair value of oil and gas properties acquired
|
330,055
|
|
|
84,222
|
|
||
Working capital
|
(6,135
|
)
|
|
2,232
|
|
||
Asset retirement obligation
|
(2,113
|
)
|
|
(1,618
|
)
|
||
Total fair value of net assets acquired
|
$
|
321,807
|
|
|
$
|
84,836
|
|
•
|
Rocky Mountain Acquisitions.
In addition to the Gooseneck property acquisitions discussed above, the Company acquired other proved and unproved properties in its Rocky Mountain region during 2014, primarily in the Powder River Basin, in multiple transactions for approximately
$135.5 million
in total cash consideration after final closing adjustments, plus approximately
7,000
net acres of non-core assets in the Company’s Rocky Mountain region.
|
•
|
Rocky Mountain Divestitures.
During the third quarter of 2016, the Company divested certain non-core properties in the Williston Basin and Powder River Basin in two separate packages for total cash received at closing, net of commissions and payments to Net Profits Plan participants (referred throughout this report as “net divestiture proceeds”), of
$110.6 million
. The Company recorded a net gain of
$16.4 million
related to these divested assets for the year ended
December 31, 2016
.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Income (loss) before income taxes
(1)
|
$
|
(6,601
|
)
|
|
$
|
(12,530
|
)
|
|
$
|
197,256
|
|
(1)
|
Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes includes impairment of proved properties expense of approximately
$17.8 million
for the year ended December 31, 2015.
|
•
|
Permian Divestiture.
During the third quarter of 2016, the Company divested its non-core properties in southeast New Mexico for net divestiture proceeds of
$54.6 million
and recorded a net loss of
$10.1 million
for the year ended
December 31, 2016
.
|
•
|
Mid-Continent Divestiture.
During the second quarter of 2015, the Company divested its Mid-Continent assets in multiple transactions for total net divestiture proceeds of
$310.3 million
and a final net gain of
$108.4 million
. In conjunction with the divestiture of its Mid-Continent assets, the Company closed its Tulsa, Oklahoma office. Please refer to
Note 14 - Exit and Disposal Costs
for additional discussion.
|
•
|
Permian Divestiture.
During the fourth quarter of 2015, the Company divested certain non-core assets in its Permian region. Net divestiture proceeds were
$25.1 million
and the final net gain on this divestiture was
$2.3 million
.
|
•
|
Rocky Mountain Divestiture.
During the second quarter of 2014, the Company divested certain non-core assets in the Montana portion of the Williston Basin. Net divestiture proceeds were
$42.0 million
and the final net gain on this divestiture was
$26.9 million
.
|
•
|
Oil swap contracts through the fourth quarter of 2021 for a total of
4.3 million
Bbls of oil production at contract prices ranging from
$54.05
to
$57.00
per Bbl.
|
•
|
Gas swap contracts through the fourth quarter of 2021 for a total of
4.6 million
MMBtu of gas production at contract prices ranging from
$2.82
to
$2.99
per MMBtu.
|
•
|
NGL swap contracts through the fourth quarter of 2019 for a total of
4.5 million
Bbls of NGL production at contract prices ranging from
$11.81
to
$48.51
per Bbl.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Income (loss) before income taxes
(1)
|
$
|
(218,506
|
)
|
|
$
|
71,556
|
|
|
$
|
294,376
|
|
(1)
|
Income (loss) before income taxes reflects oil, gas, and NGL production revenue less oil, gas, and NGL production expense and depletion, depreciation, amortization, and asset retirement obligation liability accretion expense. Additionally, loss before income taxes for the year ended
December 31, 2016
, includes
$269.6 million
of proved property impairment expense.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
Current portion of income tax expense
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
2,932
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
|
1,539
|
|
|
1,571
|
|
|
868
|
|
|||
Deferred portion of income tax expense (benefit)
|
|
(448,643
|
)
|
|
(276,722
|
)
|
|
397,780
|
|
|||
Total income tax expense (benefit)
|
|
$
|
(444,172
|
)
|
|
$
|
(275,151
|
)
|
|
$
|
398,648
|
|
Effective tax rate
|
|
37.0
|
%
|
|
38.1
|
%
|
|
37.4
|
%
|
|
|
As of December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(in thousands)
|
||||||
Deferred tax liabilities:
|
|
|
|
|
||||
Oil and gas properties
|
|
$
|
518,394
|
|
|
$
|
854,029
|
|
Derivative asset
|
|
—
|
|
|
179,543
|
|
||
Other
|
|
7,733
|
|
|
1,233
|
|
||
Total deferred tax liabilities
|
|
526,127
|
|
|
1,034,805
|
|
||
Deferred tax assets:
|
|
|
|
|
|
|
||
Federal and state tax net operating loss carryovers
|
|
151,343
|
|
|
244,942
|
|
||
Derivative liability
|
|
31,349
|
|
|
—
|
|
||
Stock compensation
|
|
10,083
|
|
|
14,529
|
|
||
Credit carryover
|
|
12,448
|
|
|
6,952
|
|
||
Other liabilities
|
|
10,567
|
|
|
20,497
|
|
||
Total deferred tax assets
|
|
215,790
|
|
|
286,920
|
|
||
Valuation allowance
|
|
(5,335
|
)
|
|
(10,394
|
)
|
||
Net deferred tax assets
|
|
210,455
|
|
|
276,526
|
|
||
Total net deferred tax liabilities
|
|
$
|
315,672
|
|
|
$
|
758,279
|
|
Current federal income tax refundable
|
|
$
|
644
|
|
|
$
|
5,378
|
|
Current state income tax refundable
|
|
$
|
—
|
|
|
$
|
65
|
|
Current state income tax payable
|
|
$
|
1,181
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Federal statutory tax expense (benefit)
|
$
|
(420,671
|
)
|
|
$
|
(253,001
|
)
|
|
$
|
372,644
|
|
Increase (decrease) in tax resulting from:
|
|
|
|
|
|
||||||
State tax expense (benefit) (net of federal benefit)
|
(17,549
|
)
|
|
(21,583
|
)
|
|
21,350
|
|
|||
Change in valuation allowance
|
(5,059
|
)
|
|
3,148
|
|
|
2,245
|
|
|||
Research and development credit
|
—
|
|
|
(1,971
|
)
|
|
—
|
|
|||
Other
|
(893
|
)
|
|
(1,744
|
)
|
|
2,409
|
|
|||
Income tax expense (benefit)
|
$
|
(444,172
|
)
|
|
$
|
(275,151
|
)
|
|
$
|
398,648
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
2,782
|
|
|
$
|
1,582
|
|
|
$
|
2,358
|
|
Additions for tax positions of prior years
|
9
|
|
|
1,200
|
|
|
140
|
|
|||
Settlements
|
(2,345
|
)
|
|
—
|
|
|
(916
|
)
|
|||
Ending balance
|
$
|
446
|
|
|
$
|
2,782
|
|
|
$
|
1,582
|
|
•
|
On
April 8, 2016
, as part of the regular, semi-annual borrowing base redetermination process, the Company entered into a Sixth Amendment to the Credit Agreement, which reduced the Company’s borrowing base to
$1.25 billion
from
$2.0 billion
at December 31, 2015. This expected reduction was primarily due to a decline in commodity prices, which resulted in a decrease in the Company’s proved reserves as of December 31, 2015. The amendment also reduced the aggregate lender commitments to
$1.25 billion
, and changed the required percentage of oil and gas properties subject to a mortgage to at least
90 percent
of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Further, this amendment revised certain of the Company’s covenants under the Credit Agreement and modified the borrowing base utilization grid, as discussed below. The Company incurred approximately
$3.1 million
in deferred financing costs associated with this amendment to the Credit Agreement.
|
•
|
On
August 8, 2016
, the Company entered into a Seventh Amendment to the Credit Agreement to allow for capped call transactions.
|
•
|
Upon issuing the Senior Convertible Notes and 2026 Notes (as defined and discussed below) during the third quarter of 2016, the Company’s borrowing base and aggregate lender commitments were reduced to
$1.1 billion
.
|
•
|
On September 30, 2016, as part of the regular, semi-annual borrowing base redetermination process, the Company entered into an Eighth Amendment to the Credit Agreement, which increased the Company’s borrowing base to
$1.35 billion
and the aggregate lender commitments to
$1.25 billion
due to an increase in commodity prices and the value of the proved reserves associated with the Rock Oil Acquisition.
|
•
|
On
December 1, 2016
, the Company’s borrowing base and aggregate lender commitments were reduced to
$1.17 billion
as a result of closing the sale of the Company’s Raven/Bear Den assets.
|
Borrowing Base Utilization Percentage
|
|
<25%
|
|
≥25% <50%
|
|
≥50% <75%
|
|
≥75% <90%
|
|
≥90%
|
|||||
Eurodollar Loans
|
|
1.750
|
%
|
|
2.000
|
%
|
|
2.250
|
%
|
|
2.500
|
%
|
|
2.750
|
%
|
ABR Loans or Swingline Loans
|
|
0.750
|
%
|
|
1.000
|
%
|
|
1.250
|
%
|
|
1.500
|
%
|
|
1.750
|
%
|
Commitment Fee Rate
|
|
0.300
|
%
|
|
0.300
|
%
|
|
0.350
|
%
|
|
0.375
|
%
|
|
0.375
|
%
|
|
As of February 15, 2017
|
|
As of December 31, 2016
|
|
As of December 31, 2015
|
||||||
|
(in thousands)
|
||||||||||
Credit facility balance
(1)
|
$
|
103,500
|
|
|
$
|
—
|
|
|
$
|
202,000
|
|
Letters of credit
(2)
|
200
|
|
|
200
|
|
|
200
|
|
|||
Available borrowing capacity
|
1,061,300
|
|
|
1,164,800
|
|
|
1,297,800
|
|
|||
Total aggregate lender commitment amount
|
$
|
1,165,000
|
|
|
$
|
1,165,000
|
|
|
$
|
1,500,000
|
|
(1)
|
Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled
$5.9 million
and
$4.9 million
as of
December 31, 2016
, and
2015
, respectively.
|
(2)
|
Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.
|
|
As of December 31,
|
||||||||||||||||||||||
|
2016
|
|
2015
|
||||||||||||||||||||
|
Principal Amount
|
|
Unamortized Deferred Financing Costs
|
|
Senior Notes, Net of Unamortized Deferred Financing Costs
|
|
Principal Amount
|
|
Unamortized Deferred Financing Costs
|
|
Senior Notes, Net of Unamortized Deferred Financing Costs
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
6.50% Senior Notes due 2021
|
$
|
346,955
|
|
|
$
|
3,372
|
|
|
$
|
343,583
|
|
|
$
|
350,000
|
|
|
$
|
4,106
|
|
|
$
|
345,894
|
|
6.125% Senior Notes due 2022
|
561,796
|
|
|
6,979
|
|
|
554,817
|
|
|
600,000
|
|
|
8,714
|
|
|
591,286
|
|
||||||
6.50% Senior Notes due 2023
|
394,985
|
|
|
4,436
|
|
|
390,549
|
|
|
400,000
|
|
|
5,231
|
|
|
394,769
|
|
||||||
5.0% Senior Notes due 2024
|
500,000
|
|
|
6,533
|
|
|
493,467
|
|
|
500,000
|
|
|
7,455
|
|
|
492,545
|
|
||||||
5.625% Senior Notes due 2025
|
500,000
|
|
|
7,619
|
|
|
492,381
|
|
|
500,000
|
|
|
8,524
|
|
|
491,476
|
|
||||||
6.75% Senior Notes due 2026
|
500,000
|
|
|
8,078
|
|
|
491,922
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total
|
$
|
2,803,736
|
|
|
$
|
37,017
|
|
|
$
|
2,766,719
|
|
|
$
|
2,350,000
|
|
|
$
|
34,030
|
|
|
$
|
2,315,970
|
|
|
As of December 31, 2016
|
||
|
(in thousands)
|
||
Principal amount of Senior Convertible Notes
|
$
|
172,500
|
|
Unamortized debt discount
|
(37,513
|
)
|
|
Unamortized deferred financing costs
|
(4,131
|
)
|
|
Net carrying amount
|
$
|
130,856
|
|
|
As of December 31, 2016
|
||
|
(in thousands)
|
||
Equity component due to allocation of proceeds to equity
|
$
|
40,217
|
|
Less: related issuance costs
|
(1,375
|
)
|
|
Less: deferred tax liability
|
(5,267
|
)
|
|
Net carrying amount
|
$
|
33,575
|
|
Years Ending December 31,
|
|
Amount
(1)
(in thousands)
|
||
2017
|
|
$
|
145,075
|
|
2018
|
|
148,240
|
|
|
2019
|
|
144,379
|
|
|
2020
|
|
141,010
|
|
|
2021
|
|
141,654
|
|
|
Thereafter
|
|
337,745
|
|
|
Total
|
|
$
|
1,058,103
|
|
(1)
|
During the third quarter of 2015, the Company closed its office in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive
$2.7 million
of total sublease income through
2019
.
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
|
PSUs
|
|
Weighted-Average Grant-Date Fair Value
|
|
PSUs
|
|
Weighted-Average Grant-Date Fair Value
|
|
PSUs
|
|
Weighted-Average Grant-Date Fair Value
|
|||||||||
Non-vested at beginning of year
(1)
|
626,328
|
|
|
$
|
61.81
|
|
|
433,660
|
|
|
$
|
73.63
|
|
|
572,469
|
|
|
$
|
66.07
|
|
Granted
(1)
|
447,971
|
|
|
$
|
26.56
|
|
|
320,753
|
|
|
$
|
45.34
|
|
|
202,404
|
|
|
$
|
94.66
|
|
Vested
(1)
|
(130,353
|
)
|
|
$
|
64.17
|
|
|
(76,438
|
)
|
|
$
|
51.76
|
|
|
(206,830
|
)
|
|
$
|
64.79
|
|
Forfeited
(1)
|
(115,023
|
)
|
|
$
|
55.59
|
|
|
(51,647
|
)
|
|
$
|
73.62
|
|
|
(134,383
|
)
|
|
$
|
86.72
|
|
Non-vested at end of year
(1)
|
828,923
|
|
|
$
|
43.25
|
|
|
626,328
|
|
|
$
|
61.81
|
|
|
433,660
|
|
|
$
|
73.63
|
|
(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,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Shares of common stock issued to settle PSUs
(1)
|
44,870
|
|
|
288,962
|
|
|
130,163
|
|
Less: shares of common stock withheld for income and payroll taxes
|
(14,809
|
)
|
|
(100,683
|
)
|
|
(45,042
|
)
|
Net shares of common stock issued
|
30,061
|
|
|
188,279
|
|
|
85,121
|
|
|
|
|
|
|
|
|||
Multiplier earned
|
0.2
|
|
|
1.0
|
|
|
0.55
|
|
(1)
|
During the years ended
December 31, 2016
,
2015
, and
2014
, the Company issued shares of common stock for PSUs granted in 2013, 2012, and 2011. The Company and the 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,
|
|||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
|
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
|
543,737
|
|
|
$
|
55.01
|
|
|
515,724
|
|
|
$
|
68.29
|
|
|
580,431
|
|
|
$
|
57.05
|
|
Granted
|
417,065
|
|
|
$
|
28.08
|
|
|
356,246
|
|
|
$
|
43.72
|
|
|
234,560
|
|
|
$
|
83.98
|
|
Vested
|
(241,363
|
)
|
|
$
|
58.06
|
|
|
(278,289
|
)
|
|
$
|
63.12
|
|
|
(253,031
|
)
|
|
$
|
58.19
|
|
Forfeited
|
(115,323
|
)
|
|
$
|
43.52
|
|
|
(49,944
|
)
|
|
$
|
66.53
|
|
|
(46,236
|
)
|
|
$
|
62.06
|
|
Non-vested at end of year
|
604,116
|
|
|
$
|
37.39
|
|
|
543,737
|
|
|
$
|
55.01
|
|
|
515,724
|
|
|
$
|
68.29
|
|
|
For the Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Shares of common stock issued to settle RSUs
(1)
|
241,363
|
|
|
278,289
|
|
|
253,031
|
|
Less: shares of common stock withheld for income and payroll taxes
|
(72,181
|
)
|
|
(91,045
|
)
|
|
(81,434
|
)
|
Net shares of common stock issued
|
169,182
|
|
|
187,244
|
|
|
171,597
|
|
(1)
|
During the years ended
December 31, 2016
,
2015
, and
2014
, the Company issued shares of common stock for RSUs granted in previous years. The Company and the 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.
|
|
Shares
|
|
Weighted-Average Exercise Price
|
|
Aggregate Intrinsic Value
|
|||||
For the year ended December 31, 2014
|
|
|
|
|
|
|||||
Outstanding, start of year
|
39,088
|
|
|
$
|
20.87
|
|
|
$
|
—
|
|
Exercised
|
(39,088
|
)
|
|
$
|
20.87
|
|
|
$
|
1,993,726
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Outstanding, end of year
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Vested and exercisable at end of year
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Risk free interest rate
|
0.4
|
%
|
|
0.1
|
%
|
|
0.1
|
%
|
Dividend yield
|
0.4
|
%
|
|
0.2
|
%
|
|
0.1
|
%
|
Volatility factor of the expected market
price of the Company’s common stock
|
95.0
|
%
|
|
61.2
|
%
|
|
33.0
|
%
|
Expected life (in years)
|
0.5
|
|
|
0.5
|
|
|
0.5
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Cash payments made or accrued related to operations
|
$
|
6,608
|
|
|
$
|
3,498
|
|
|
$
|
9,016
|
|
Cash payments made or accrued related to divestitures
|
24,349
|
|
|
3,789
|
|
|
8,341
|
|
|||
Total net settlements
|
$
|
30,957
|
|
|
$
|
7,287
|
|
|
$
|
17,357
|
|
|
For the Years Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Change in benefit obligation:
|
|
|
|
||||
Projected benefit obligation at beginning of year
|
$
|
62,547
|
|
|
$
|
57,867
|
|
Service cost
|
8,200
|
|
|
7,949
|
|
||
Interest cost
|
2,908
|
|
|
2,496
|
|
||
Actuarial loss
|
2,662
|
|
|
2,397
|
|
||
Benefits paid
|
(6,658
|
)
|
|
(8,162
|
)
|
||
Projected benefit obligation at end of year
|
69,659
|
|
|
62,547
|
|
||
|
|
|
|
||||
Change in plan assets:
|
|
|
|
||||
Fair value of plan assets at beginning of year
|
25,769
|
|
|
27,940
|
|
||
Actual return on plan assets
|
1,575
|
|
|
(410
|
)
|
||
Employer contribution
|
11,045
|
|
|
6,401
|
|
||
Benefits paid
|
(6,658
|
)
|
|
(8,162
|
)
|
||
Fair value of plan assets at end of year
|
31,731
|
|
|
25,769
|
|
||
Funded status at end of year
|
$
|
(37,928
|
)
|
|
$
|
(36,778
|
)
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Projected benefit obligation
|
$
|
69,659
|
|
|
$
|
62,547
|
|
|
|
|
|
||||
Accumulated benefit obligation
|
$
|
54,681
|
|
|
$
|
46,439
|
|
Less: Fair value of plan assets
|
(31,731
|
)
|
|
(25,769
|
)
|
||
Underfunded accumulated benefit obligation
|
$
|
22,950
|
|
|
$
|
20,670
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Unrecognized actuarial losses
|
$
|
22,708
|
|
|
$
|
20,966
|
|
|
$
|
17,812
|
|
Unrecognized prior service costs
|
83
|
|
|
101
|
|
|
118
|
|
|||
Unrecognized transition obligation
|
—
|
|
|
—
|
|
|
—
|
|
|||
Accumulated other comprehensive loss
|
$
|
22,791
|
|
|
$
|
21,067
|
|
|
$
|
17,930
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Net actuarial loss
|
$
|
(3,322
|
)
|
|
$
|
(4,990
|
)
|
|
$
|
(10,062
|
)
|
Prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|||
Less:
|
|
|
|
|
|
||||||
Amortization of prior service cost
|
(16
|
)
|
|
(17
|
)
|
|
(17
|
)
|
|||
Amortization of net actuarial loss
|
(1,582
|
)
|
|
(1,486
|
)
|
|
(689
|
)
|
|||
Settlements
|
—
|
|
|
(350
|
)
|
|
—
|
|
|||
Total other comprehensive loss
|
$
|
(1,724
|
)
|
|
$
|
(3,137
|
)
|
|
$
|
(9,356
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
||||||
Service cost
|
$
|
8,200
|
|
|
$
|
7,949
|
|
|
$
|
6,335
|
|
Interest cost
|
2,908
|
|
|
2,496
|
|
|
2,191
|
|
|||
Expected return on plan assets that reduces periodic pension cost
|
(2,235
|
)
|
|
(2,182
|
)
|
|
(1,978
|
)
|
|||
Amortization of prior service cost
|
16
|
|
|
17
|
|
|
17
|
|
|||
Amortization of net actuarial loss
|
1,582
|
|
|
1,486
|
|
|
689
|
|
|||
Settlements
|
—
|
|
|
350
|
|
|
—
|
|
|||
Net periodic benefit cost
|
$
|
10,471
|
|
|
$
|
10,116
|
|
|
$
|
7,254
|
|
|
As of December 31,
|
||||
|
2016
|
|
2015
|
|
2014
|
Projected benefit obligation
|
|
|
|
|
|
Discount rate
|
4.2%
|
|
4.7%
|
|
4.3%
|
Rate of compensation increase
|
6.2%
|
|
6.2%
|
|
6.2%
|
Net periodic benefit cost
|
|
|
|
|
|
Discount rate
|
4.7%
|
|
4.3%
|
|
5.0%
|
Expected return on plan assets
(1)
|
7.5%
|
|
7.5%
|
|
7.5%
|
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
|
2017
|
|
2016
|
|
2015
|
|||
Equity securities
|
35.0
|
%
|
|
28.8
|
%
|
|
39.1
|
%
|
Fixed income securities
|
43.0
|
%
|
|
35.5
|
%
|
|
34.0
|
%
|
Other securities
|
22.0
|
%
|
|
35.7
|
%
|
|
26.9
|
%
|
Total
|
100.0
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
|
|
|
|
|
Fair Value Measurements Using:
|
|||||||||||||
|
Actual Asset Allocation
|
|
Total
|
|
Level 1 Inputs
|
|
Level 2 Inputs
|
|
Level 3 Inputs
|
|||||||||
|
|
|
(in thousands)
|
|||||||||||||||
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|||||||||
Cash
|
—
|
%
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Domestic
(1)
|
18.7
|
%
|
|
5,945
|
|
|
4,471
|
|
|
1,474
|
|
|
—
|
|
||||
International
(2)
|
10.1
|
%
|
|
3,192
|
|
|
3,192
|
|
|
—
|
|
|
—
|
|
||||
Total Equity Securities
|
28.8
|
%
|
|
9,137
|
|
|
7,663
|
|
|
1,474
|
|
|
—
|
|
||||
Fixed Income Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
High-Yield Bonds
(3)
|
2.6
|
%
|
|
822
|
|
|
822
|
|
|
—
|
|
|
—
|
|
||||
Core Fixed Income
(4)
|
25.0
|
%
|
|
7,923
|
|
|
7,923
|
|
|
—
|
|
|
—
|
|
||||
Floating Rate Corp Loans
(5)
|
7.9
|
%
|
|
2,495
|
|
|
2,495
|
|
|
—
|
|
|
—
|
|
||||
Total Fixed Income Securities
|
35.5
|
%
|
|
11,240
|
|
|
11,240
|
|
|
—
|
|
|
—
|
|
||||
Other Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Commodities
(6)
|
1.8
|
%
|
|
578
|
|
|
578
|
|
|
—
|
|
|
—
|
|
||||
Real Estate
(7)
|
5.1
|
%
|
|
1,629
|
|
|
—
|
|
|
—
|
|
|
1,629
|
|
||||
Collective Investment Trusts
(8)
|
17.5
|
%
|
|
5,562
|
|
|
—
|
|
|
5,562
|
|
|
—
|
|
||||
Hedge Fund
(9)
|
11.3
|
%
|
|
3,585
|
|
|
—
|
|
|
—
|
|
|
3,585
|
|
||||
Total Other Securities
|
35.7
|
%
|
|
11,354
|
|
|
578
|
|
|
5,562
|
|
|
5,214
|
|
||||
Total Investments
|
100.0
|
%
|
|
$
|
31,731
|
|
|
$
|
19,481
|
|
|
$
|
7,036
|
|
|
$
|
5,214
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
As of December 31, 2015
|
|
|
|
|
|
|
|
|
|
|||||||||
Cash
|
—
|
%
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity Securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Domestic
(1)
|
26.1
|
%
|
|
6,729
|
|
|
4,943
|
|
|
1,786
|
|
|
—
|
|
||||
International
(2)
|
13.0
|
%
|
|
3,353
|
|
|
3,353
|
|
|
—
|
|
|
—
|
|
||||
Total Equity Securities
|
39.1
|
%
|
|
10,082
|
|
|
8,296
|
|
|
1,786
|
|
|
—
|
|
||||
Fixed Income Securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
High-Yield Bonds
(3)
|
2.8
|
%
|
|
722
|
|
|
722
|
|
|
—
|
|
|
—
|
|
||||
Core Fixed Income
(4)
|
22.5
|
%
|
|
5,789
|
|
|
5,789
|
|
|
—
|
|
|
—
|
|
||||
Floating Rate Corp Loans
(5)
|
8.7
|
%
|
|
2,247
|
|
|
2,247
|
|
|
—
|
|
|
—
|
|
||||
Total Fixed Income Securities
|
34.0
|
%
|
|
8,758
|
|
|
8,758
|
|
|
—
|
|
|
—
|
|
||||
Other Securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Commodities
(6)
|
2.7
|
%
|
|
700
|
|
|
700
|
|
|
—
|
|
|
—
|
|
||||
Real Estate
(7)
|
5.8
|
%
|
|
1,499
|
|
|
—
|
|
|
—
|
|
|
1,499
|
|
||||
Collective Investment Trusts
(8)
|
4.6
|
%
|
|
1,184
|
|
|
—
|
|
|
1,184
|
|
|
—
|
|
||||
Hedge Fund
(9)
|
13.8
|
%
|
|
3,546
|
|
|
—
|
|
|
—
|
|
|
3,546
|
|
||||
Total Other Securities
|
26.9
|
%
|
|
6,929
|
|
|
700
|
|
|
1,184
|
|
|
5,045
|
|
||||
Total Investments
|
100.0
|
%
|
|
$
|
25,769
|
|
|
$
|
17,754
|
|
|
$
|
2,970
|
|
|
$
|
5,045
|
|
(1)
|
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 this fund is to approximate the S&P 500 by investing in one or more collective investment funds.
|
(2)
|
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.
|
(3)
|
High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis.
|
(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)
|
Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities.
|
(7)
|
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.
|
(8)
|
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.
|
(9)
|
The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses 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, 2015
|
$
|
4,864
|
|
Purchases
|
—
|
|
|
Realized gain on assets
|
165
|
|
|
Unrealized gain on assets
|
16
|
|
|
Balance at December 31, 2015
|
$
|
5,045
|
|
Purchases
|
561
|
|
|
Realized gain on assets
|
54
|
|
|
Unrealized gain on assets
|
115
|
|
|
Disposition
|
(561
|
)
|
|
Balance at December 31, 2016
|
$
|
5,214
|
|
Years Ending December 31,
|
|
(in thousands)
|
||
2017
|
|
$
|
6,532
|
|
2018
|
|
$
|
3,256
|
|
2019
|
|
$
|
4,480
|
|
2020
|
|
$
|
4,778
|
|
2021
|
|
$
|
5,772
|
|
2022 through 2026
|
|
$
|
38,708
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Beginning asset retirement obligation
|
$
|
140,874
|
|
|
$
|
122,124
|
|
Liabilities incurred
(1)
|
21,293
|
|
|
14,471
|
|
||
Liabilities settled
(2)
|
(57,100
|
)
|
|
(24,781
|
)
|
||
Accretion expense
|
7,795
|
|
|
5,091
|
|
||
Revision to estimated cash flows
|
10,445
|
|
|
23,969
|
|
||
Ending asset retirement obligation
(3)(4)
|
$
|
123,307
|
|
|
$
|
140,874
|
|
(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)
|
Balance as of December 31, 2016, included
$26.2 million
of asset retirement obligations associated with oil and gas properties held for sale, specifically the Company’s outside-operated Eagle Ford shale assets. There were
no
material asset retirement obligations related to assets held for sale as of December 31, 2015.
|
(4)
|
Balances as of
December 31, 2016
, and
2015
, included
$932,000
and
$3.3 million
, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in accounts payable and accrued expenses on the accompanying balance sheets.
|
Contract Period
|
|
NYMEX WTI Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(MBbls)
|
|
(per Bbl)
|
|||
First quarter 2017
|
|
1,574
|
|
|
$
|
46.41
|
|
Second quarter 2017
|
|
1,444
|
|
|
$
|
46.44
|
|
Third quarter 2017
|
|
1,340
|
|
|
$
|
46.66
|
|
Fourth quarter 2017
|
|
1,254
|
|
|
$
|
46.35
|
|
Total
|
|
5,612
|
|
|
|
Contract Period
|
|
NYMEX WTI Volumes
|
|
Weighted-
Average Floor
Price
|
|
Weighted-
Average Ceiling
Price
|
|||||
|
|
(MBbls)
|
|
(per Bbl)
|
|
(per Bbl)
|
|||||
First quarter 2017
|
|
704
|
|
|
$
|
45.00
|
|
|
$
|
54.17
|
|
Second quarter 2017
|
|
636
|
|
|
$
|
45.00
|
|
|
$
|
54.10
|
|
Third quarter 2017
|
|
583
|
|
|
$
|
45.00
|
|
|
$
|
54.05
|
|
Fourth quarter 2017
|
|
540
|
|
|
$
|
45.00
|
|
|
$
|
54.01
|
|
2018
|
|
2,312
|
|
|
$
|
50.00
|
|
|
$
|
59.24
|
|
2019
|
|
943
|
|
|
$
|
50.00
|
|
|
$
|
61.15
|
|
Total
|
|
5,718
|
|
|
|
|
|
Contract Period
|
|
Sold Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Purchased Volumes
(1)
|
|
Weighted-
Average
Contract
Price
|
|
Net Volumes
|
|||||||
|
|
(BBtu)
|
|
(per MMBtu)
|
|
(BBtu)
|
|
(per MMBtu)
|
|
(BBtu)
|
|||||||
First quarter 2017
|
|
29,420
|
|
|
$
|
3.76
|
|
|
—
|
|
|
$
|
—
|
|
|
29,420
|
|
Second quarter 2017
|
|
26,205
|
|
|
$
|
3.98
|
|
|
—
|
|
|
$
|
—
|
|
|
26,205
|
|
Third quarter 2017
|
|
23,657
|
|
|
$
|
4.01
|
|
|
—
|
|
|
$
|
—
|
|
|
23,657
|
|
Fourth quarter 2017
|
|
22,001
|
|
|
$
|
3.98
|
|
|
—
|
|
|
$
|
—
|
|
|
22,001
|
|
2018
|
|
63,166
|
|
|
$
|
3.68
|
|
|
(30,606
|
)
|
|
$
|
4.27
|
|
|
32,560
|
|
2019
|
|
27,743
|
|
|
$
|
4.20
|
|
|
(24,415
|
)
|
|
$
|
4.34
|
|
|
3,328
|
|
Total
(2)
|
|
192,192
|
|
|
|
|
(55,021
|
)
|
|
|
|
137,171
|
|
(1)
|
During 2016, the Company restructured certain of its gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling
55.0 million
MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling
38.6 million
MMBtu with a contract price of
$4.43
per MMBtu. No cash or other consideration was included as part of the restructuring.
|
(2)
|
Total net volumes of natural gas swaps are comprised of
IF El Paso Permian
(
3%
),
IF HSC
(
94%
), and
IF NNG Ventura
(
3%
).
|
|
|
OPIS Purity Ethane Mont Belvieu
|
|
OPIS Propane Mont Belvieu Non-TET
|
|
OPIS Normal Butane Mont Belvieu Non-TET
|
|
OPIS Isobutane Mont Belvieu Non-TET
|
|
OPIS Natural Gasoline Mont Belvieu Non-TET
|
||||||||||||||||||||
Contract Period
|
|
Volumes
|
Weighted-Average
Contract Price
|
|
Volumes
|
Weighted-Average
Contract Price |
|
Volumes
|
Weighted-Average
Contract Price |
|
Volumes
|
Weighted-Average
Contract Price |
|
Volumes
|
Weighted-Average
Contract Price |
|||||||||||||||
|
|
(MBbls)
|
(per Bbl)
|
|
(MBbls)
|
(per Bbl)
|
|
(MBbls)
|
(per Bbl)
|
|
(MBbls)
|
(per Bbl)
|
|
(MBbls)
|
(per Bbl)
|
|||||||||||||||
First quarter 2017
|
|
847
|
|
$
|
8.63
|
|
|
692
|
|
$
|
21.90
|
|
|
122
|
|
$
|
30.69
|
|
|
94
|
|
$
|
31.12
|
|
|
156
|
|
$
|
47.54
|
|
Second quarter 2017
|
|
787
|
|
$
|
8.86
|
|
|
634
|
|
$
|
21.90
|
|
|
112
|
|
$
|
30.69
|
|
|
86
|
|
$
|
31.12
|
|
|
143
|
|
$
|
47.56
|
|
Third quarter 2017
|
|
736
|
|
$
|
9.14
|
|
|
588
|
|
$
|
21.91
|
|
|
104
|
|
$
|
30.70
|
|
|
80
|
|
$
|
31.12
|
|
|
133
|
|
$
|
47.59
|
|
Fourth quarter 2017
|
|
692
|
|
$
|
9.10
|
|
|
550
|
|
$
|
21.91
|
|
|
98
|
|
$
|
30.70
|
|
|
74
|
|
$
|
31.12
|
|
|
124
|
|
$
|
47.61
|
|
2018
|
|
2,434
|
|
$
|
10.18
|
|
|
1,442
|
|
$
|
22.86
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
2019
|
|
2,176
|
|
$
|
11.95
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
2020
|
|
539
|
|
$
|
11.13
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
Total
|
|
8,211
|
|
|
|
3,906
|
|
|
|
436
|
|
|
|
334
|
|
|
|
556
|
|
|
•
|
derivative costless collar contracts through the fourth quarter of 2019 for a total of
2.7 million
Bbls of oil production with contract floor prices of
$50.00
per Bbl and contract ceiling prices ranging from
$57.00
per Bbl to
$58.40
per Bbl;
|
•
|
derivative fixed price Midland-Cushing basis swap contracts through the fourth quarter of 2019 for a total of
3.7 million
Bbls of oil production at contract prices ranging from
($1.23)
per Bbl to
($1.45)
per Bbl; and
|
•
|
derivative fixed price swap contracts through the first quarter of 2018 for a total of
1.1 million
Bbls of NGL production at contract prices ranging from
$35.07
per Bbl to
$49.88
per Bbl.
|
|
As of December 31, 2016
|
||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
||||
|
(in thousands)
|
||||||||||
Commodity contracts
|
Current assets
|
|
$
|
54,521
|
|
|
Current liabilities
|
|
$
|
115,464
|
|
Commodity contracts
|
Noncurrent assets
|
|
67,575
|
|
|
Noncurrent liabilities
|
|
98,340
|
|
||
Derivatives not designated as hedging instruments
|
|
|
$
|
122,096
|
|
|
|
|
$
|
213,804
|
|
|
As of December 31, 2015
|
||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
||||
|
(in thousands)
|
||||||||||
Commodity contracts
|
Current assets
|
|
$
|
367,710
|
|
|
Current liabilities
|
|
$
|
8
|
|
Commodity contracts
|
Noncurrent assets
|
|
120,701
|
|
|
Noncurrent liabilities
|
|
—
|
|
||
Derivatives not designated as hedging instruments
|
|
|
$
|
488,411
|
|
|
|
|
$
|
8
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||
|
|
As of December 31,
|
|
As of December 31,
|
||||||||||||
Offsetting of Derivative Assets and Liabilities
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
|
|
(in thousands)
|
||||||||||||||
Gross amounts presented in the accompanying balance sheets
|
|
$
|
122,096
|
|
|
$
|
488,411
|
|
|
$
|
(213,804
|
)
|
|
$
|
(8
|
)
|
Amounts not offset in the accompanying balance sheets
|
|
(118,080
|
)
|
|
(8
|
)
|
|
118,080
|
|
|
8
|
|
||||
Net amounts
|
|
$
|
4,016
|
|
|
$
|
488,403
|
|
|
$
|
(95,724
|
)
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Derivative settlement (gain) loss:
|
|
|
|
|
|
||||||
Oil contracts
|
$
|
(243,102
|
)
|
|
$
|
(362,219
|
)
|
|
$
|
(28,410
|
)
|
Gas contracts
(1)
|
(94,936
|
)
|
|
(123,180
|
)
|
|
26,706
|
|
|||
NGL contracts
|
8,560
|
|
|
(27,167
|
)
|
|
(10,911
|
)
|
|||
Total derivative settlement gain
|
$
|
(329,478
|
)
|
|
$
|
(512,566
|
)
|
|
$
|
(12,615
|
)
|
|
|
|
|
|
|
||||||
Total derivative (gain) loss:
|
|
|
|
|
|
||||||
Oil contracts
|
$
|
85,370
|
|
|
$
|
(191,165
|
)
|
|
$
|
(457,082
|
)
|
Gas contracts
|
81,060
|
|
|
(189,734
|
)
|
|
(93,267
|
)
|
|||
NGL contracts
|
84,203
|
|
|
(27,932
|
)
|
|
(32,915
|
)
|
|||
Total net derivative (gain) loss
|
$
|
250,633
|
|
|
$
|
(408,831
|
)
|
|
$
|
(583,264
|
)
|
(1)
|
Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include
$15.3 million
and
$5.6 million
, respectively, of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region.
|
•
|
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)
|
$
|
—
|
|
|
$
|
122,096
|
|
|
$
|
—
|
|
Total property and equipment, net
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
88,205
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
213,804
|
|
|
$
|
—
|
|
Net Profits Plan
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
411
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
(2)
|
This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
488,411
|
|
|
$
|
—
|
|
Total property and equipment, net
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
124,813
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
—
|
|
Net Profits Plan
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,611
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
(2)
|
This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Impairment of proved properties
|
$
|
354.6
|
|
|
$
|
468.7
|
|
|
$
|
84.5
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Abandonment and impairment of unproved properties
|
$
|
80.4
|
|
|
$
|
78.6
|
|
|
$
|
75.6
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
7,611
|
|
|
$
|
27,136
|
|
|
$
|
56,985
|
|
Net increase (decrease) in liability
(1)
|
23,757
|
|
|
(12,238
|
)
|
|
(12,492
|
)
|
|||
Net settlements
(1) (2)
|
(30,957
|
)
|
|
(7,287
|
)
|
|
(17,357
|
)
|
|||
Transfers in (out) of Level 3
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance
|
$
|
411
|
|
|
$
|
7,611
|
|
|
$
|
27,136
|
|
(1)
|
Net changes in the Company’s Net Profits Plan liability are shown in the change in Net Profits Plan liability line item of the accompanying statements of operations.
|
(2)
|
Settlements represent cash payments made or accrued under the Net Profits Plan and are recognized as compensation expense or a reduction to the net gain on divestiture activity line in the accompanying statements of operations, as discussed in
Note 7 – Compensation Plans.
|
|
As of December 31,
|
||||||||||||||
|
2016
|
|
2015
|
||||||||||||
|
Principal Amount
|
|
Fair Value
|
|
Principal Amount
|
|
Fair Value
|
||||||||
|
(in thousands)
|
||||||||||||||
6.50% Senior Notes due 2021
|
$
|
346,955
|
|
|
$
|
354,546
|
|
|
$
|
350,000
|
|
|
$
|
262,938
|
|
6.125% Senior Notes due 2022
|
$
|
561,796
|
|
|
$
|
570,925
|
|
|
$
|
600,000
|
|
|
$
|
440,250
|
|
6.50% Senior Notes due 2023
|
$
|
394,985
|
|
|
$
|
403,134
|
|
|
$
|
400,000
|
|
|
$
|
296,000
|
|
5.0% Senior Notes due 2024
|
$
|
500,000
|
|
|
$
|
475,975
|
|
|
$
|
500,000
|
|
|
$
|
334,065
|
|
5.625% Senior Notes due 2025
|
$
|
500,000
|
|
|
$
|
485,000
|
|
|
$
|
500,000
|
|
|
$
|
326,875
|
|
6.75% Senior Notes due 2026
|
$
|
500,000
|
|
|
$
|
516,565
|
|
|
$
|
—
|
|
|
$
|
—
|
|
1.50% Senior Convertible Notes due 2021
|
$
|
172,500
|
|
|
$
|
202,189
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance on January 1,
|
$
|
11,952
|
|
|
$
|
43,589
|
|
|
$
|
34,527
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
19,846
|
|
|
11,952
|
|
|
43,589
|
|
|||
Divestitures
|
—
|
|
|
(809
|
)
|
|
—
|
|
|||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
|
(11,952
|
)
|
|
(18,485
|
)
|
|
(33,340
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
—
|
|
|
(24,295
|
)
|
|
(1,187
|
)
|
|||
Ending balance at December 31,
|
$
|
19,846
|
|
|
$
|
11,952
|
|
|
$
|
43,589
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Development costs
(1)
|
$
|
595,331
|
|
|
$
|
1,234,114
|
|
|
$
|
1,782,324
|
|
Exploration costs
|
118,224
|
|
|
132,465
|
|
|
288,270
|
|
|||
Acquisitions
(2)
|
|
|
|
|
|
||||||
Proved properties
|
201,672
|
|
|
10,040
|
|
|
272,902
|
|
|||
Unproved properties
(3)
|
2,458,667
|
|
|
18,382
|
|
|
368,208
|
|
|||
Total, including asset retirement obligation
(4)(5)
|
$
|
3,373,894
|
|
|
$
|
1,395,001
|
|
|
$
|
2,711,704
|
|
(1)
|
Includes facility costs of
$25.9 million
,
$75.6 million
, and
$75.1 million
for the years ended
December 31, 2016
,
2015
, and
2014
, respectively.
|
(2)
|
Includes the
$437.2 million
value of the equity consideration given to the sellers of the QStar Acquisition. Please refer to
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
for additional discussion.
|
(3)
|
Includes amounts related to leasing activity outside of acquisitions of proved and unproved properties totaling
$7.5 million
,
$17.5 million
, and
$79.5 million
for the years ended December 31, 2016,
2015
, and
2014
, respectively.
|
(4)
|
Includes amounts relating to estimated asset retirement obligations of
$32.1 million
,
$38.5 million
, and
$11.4 million
for the years ended December 31, 2016,
2015
, and
2014
, respectively. For the year ended December 31, 2016,
$16.5 million
of the estimated asset retirement obligation amount relates to acquired proved properties.
|
(5)
|
Includes capitalized interest of
$17.0 million
,
$25.1 million
, and
$16.2 million
for the years ended
December 31, 2016
,
2015
, and
2014
, respectively.
|
|
||||||||||||||||||||||||||
|
For the Years Ended December 31,
|
|||||||||||||||||||||||||
|
2016
(1)
|
|
2015
(2)
|
|
2014
(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
|
145.3
|
|
|
1,264.0
|
|
|
115.4
|
|
|
169.7
|
|
|
1,466.5
|
|
|
133.5
|
|
|
126.6
|
|
|
1,189.3
|
|
|
103.9
|
|
Revisions of previous estimate
|
(36.0
|
)
|
|
(249.8
|
)
|
|
(18.6
|
)
|
|
(46.2
|
)
|
|
(369.6
|
)
|
|
(40.6
|
)
|
|
(5.1
|
)
|
|
46.0
|
|
|
7.8
|
|
Discoveries and extensions
|
7.8
|
|
|
42.5
|
|
|
4.1
|
|
|
16.9
|
|
|
122.3
|
|
|
9.3
|
|
|
15.0
|
|
|
103.5
|
|
|
10.5
|
|
Infill reserves in an existing proved field
|
32.3
|
|
|
228.1
|
|
|
18.9
|
|
|
24.9
|
|
|
356.2
|
|
|
29.7
|
|
|
32.0
|
|
|
270.8
|
|
|
24.1
|
|
Sales of
reserves
(4)
|
(40.0
|
)
|
|
(46.7
|
)
|
|
—
|
|
|
(1.9
|
)
|
|
(138.4
|
)
|
|
(0.4
|
)
|
|
(1.9
|
)
|
|
(1.1
|
)
|
|
—
|
|
Purchases of minerals in place
(4)
|
12.1
|
|
|
19.9
|
|
|
0.1
|
|
|
1.1
|
|
|
0.6
|
|
|
—
|
|
|
19.8
|
|
|
10.9
|
|
|
0.2
|
|
Production
|
(16.6
|
)
|
|
(146.9
|
)
|
|
(14.2
|
)
|
|
(19.2
|
)
|
|
(173.6
|
)
|
|
(16.1
|
)
|
|
(16.7
|
)
|
|
(152.9
|
)
|
|
(13.0
|
)
|
End of year
(5)
|
104.9
|
|
|
1,111.1
|
|
|
105.7
|
|
|
145.3
|
|
|
1,264.0
|
|
|
115.4
|
|
|
169.7
|
|
|
1,466.5
|
|
|
133.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Beginning of year
|
75.6
|
|
|
644.4
|
|
|
61.5
|
|
|
89.3
|
|
|
784.6
|
|
|
66.7
|
|
|
70.2
|
|
|
569.2
|
|
|
43.8
|
|
End of year
|
48.5
|
|
|
609.1
|
|
|
58.6
|
|
|
75.6
|
|
644.4
|
|
|
61.5
|
|
|
89.3
|
|
|
784.6
|
|
|
66.7
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Beginning of year
|
69.6
|
|
|
619.7
|
|
|
53.9
|
|
|
80.4
|
|
|
682.0
|
|
|
66.8
|
|
|
56.3
|
|
|
620.1
|
|
|
60.2
|
|
End of year
|
56.4
|
|
|
502.0
|
|
|
47.1
|
|
|
69.6
|
|
|
619.7
|
|
|
53.9
|
|
|
80.4
|
|
|
682.0
|
|
|
66.8
|
|
(1)
|
For the year ended December 31, 2016, the Company added
108.2
MMBOE from its drilling program and acquired
15.5
MMBOE. These additions were offset by net negative engineering revisions of
96.2
MMBOE, consisting of
18.1
MMBOE of negative performance revisions, a
35.1
MMBOE negative price revision, and the removal of
43.0
MMBOE of certain longer term proved undeveloped reserves reflecting the Company’s shift to develop its predominately unproven Midland Basin properties. Additionally, the Company sold
47.7
MMBOE during 2016.
|
(2)
|
For the year ended December 31, 2015, the Company added
160.6
MMBOE from its drilling program, the majority of which related to activity in the Eagle Ford shale and Bakken/Three Forks resource plays. The Company had net negative engineering revisions of
148.6
MMBOE, consisting of
47.3
MMBOE of positive performance revisions in the Eagle Ford shale and Bakken/Three Forks resource plays resulting from enhanced completions and reductions in operating expenses, offset by a
116.5
MMBOE negative price revision due to the decline in commodity prices in 2015 and the removal of
79.4
MMBOE of proved undeveloped reserves due to the five-year rule. Additionally, the Company sold
25.4
MMBOE in 2015.
|
(3)
|
For the year ended December 31, 2014, the Company added
143.9
MMBOE from its drilling program and had upward engineering revisions of
10.4
MMBOE related primarily to improved performance and lower operating expenses in its operated Eagle Ford shale assets.
|
(4)
|
Please refer to
Note 3 – Acquisitions, Divestitures, and Assets Held for Sale
for additional information.
|
(5)
|
As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, the Company entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 74.0 MMBOE of the Company’s proved reserves as of December 31, 2016. Additionally, subsequent to December 31, 2016, the Company announced plans to sell its Divide County, North Dakota assets.
|
|
As of December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Future cash inflows
|
$
|
8,359,938
|
|
|
$
|
11,337,865
|
|
|
$
|
25,897,730
|
|
Future production costs
|
(4,634,649
|
)
|
|
(6,234,687
|
)
|
|
(9,986,239
|
)
|
|||
Future development costs
|
(1,636,077
|
)
|
|
(2,005,599
|
)
|
|
(3,294,164
|
)
|
|||
Future income taxes
(1)
|
—
|
|
|
—
|
|
|
(3,511,352
|
)
|
|||
Future net cash flows
|
2,089,212
|
|
|
3,097,579
|
|
|
9,105,975
|
|
|||
10 percent annual discount
|
(937,099
|
)
|
|
(1,307,053
|
)
|
|
(3,407,192
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
1,152,113
|
|
|
$
|
1,790,526
|
|
|
$
|
5,698,783
|
|
(1)
|
Regarding the calculation as of December 31, 2016, and 2015, after evaluating all factors and giving effect to tax basis, future tax deductions, and available tax credits, the Company determined that at price levels for each respective period, future net cash flows would not be subject to federal or state income tax for the projected life of the reserves under authoritative tax legislation.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Standardized Measure, beginning of year
|
$
|
1,790,526
|
|
|
$
|
5,698,783
|
|
|
$
|
4,009,439
|
|
Sales of oil, gas, and NGLs produced, net of production costs
|
(580,861
|
)
|
|
(776,272
|
)
|
|
(1,765,666
|
)
|
|||
Net changes in prices and production costs
|
(315,725
|
)
|
|
(4,709,908
|
)
|
|
(75,966
|
)
|
|||
Extensions, discoveries and other including infill reserves in an existing proved field, net of related costs
|
242,556
|
|
|
386,069
|
|
|
1,819,657
|
|
|||
Sales of reserves in place
|
(377,607
|
)
|
|
(262,210
|
)
|
|
(49,736
|
)
|
|||
Purchase of reserves in place
|
115,270
|
|
|
4,686
|
|
|
413,175
|
|
|||
Previously estimated development costs incurred during the period
|
290,837
|
|
|
449,738
|
|
|
1,015,694
|
|
|||
Changes in estimated future development costs
|
27,961
|
|
|
191,447
|
|
|
138,247
|
|
|||
Revisions of previous quantity estimates
|
(124,845
|
)
|
|
(1,819,639
|
)
|
|
167,500
|
|
|||
Accretion of discount
|
179,050
|
|
|
761,746
|
|
|
552,852
|
|
|||
Net change in income taxes
|
—
|
|
|
1,918,670
|
|
|
(399,587
|
)
|
|||
Changes in timing and other
|
(95,049
|
)
|
|
(52,584
|
)
|
|
(126,826
|
)
|
|||
Standardized Measure, end of year
|
$
|
1,152,113
|
|
|
$
|
1,790,526
|
|
|
$
|
5,698,783
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
||||||||
Year Ended December 31, 2016
(2)
|
|
|
|
|
|
|
|
||||||||
Total operating revenues and other income
|
$
|
143,076
|
|
|
$
|
341,814
|
|
|
$
|
352,660
|
|
|
$
|
379,900
|
|
Total operating expenses
|
669,801
|
|
|
572,363
|
|
|
370,314
|
|
|
664,287
|
|
||||
Loss from operations
|
$
|
(526,725
|
)
|
|
$
|
(230,549
|
)
|
|
$
|
(17,654
|
)
|
|
$
|
(284,387
|
)
|
Loss before income taxes
|
$
|
(542,085
|
)
|
|
$
|
(264,579
|
)
|
|
$
|
(64,639
|
)
|
|
$
|
(330,613
|
)
|
Net loss
|
$
|
(347,210
|
)
|
|
$
|
(168,681
|
)
|
|
$
|
(40,907
|
)
|
|
$
|
(200,946
|
)
|
Basic net loss per common share
(1)
|
$
|
(5.10
|
)
|
|
$
|
(2.48
|
)
|
|
$
|
(0.52
|
)
|
|
$
|
(2.20
|
)
|
Diluted net loss per common share
(1)
|
$
|
(5.10
|
)
|
|
$
|
(2.48
|
)
|
|
$
|
(0.52
|
)
|
|
$
|
(2.20
|
)
|
Dividends declared per common share
|
$
|
0.05
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2015
(3)
|
|
|
|
|
|
|
|
||||||||
Total operating revenues and other income
|
$
|
365,934
|
|
|
$
|
516,146
|
|
|
$
|
371,151
|
|
|
$
|
303,734
|
|
Total operating expenses
|
420,369
|
|
|
567,025
|
|
|
339,047
|
|
|
809,307
|
|
||||
Income (loss) from operations
|
$
|
(54,435
|
)
|
|
$
|
(50,879
|
)
|
|
$
|
32,104
|
|
|
$
|
(505,573
|
)
|
Loss before income taxes
|
$
|
(86,511
|
)
|
|
$
|
(98,211
|
)
|
|
$
|
(1,026
|
)
|
|
$
|
(537,113
|
)
|
Net income (loss)
|
$
|
(53,058
|
)
|
|
$
|
(57,508
|
)
|
|
$
|
3,114
|
|
|
$
|
(340,258
|
)
|
Basic net income (loss) per common share
(1)
|
$
|
(0.79
|
)
|
|
$
|
(0.85
|
)
|
|
$
|
0.05
|
|
|
$
|
(5.01
|
)
|
Diluted net income (loss) per common share
(1)
|
$
|
(0.79
|
)
|
|
$
|
(0.85
|
)
|
|
$
|
0.05
|
|
|
$
|
(5.01
|
)
|
Dividends declared per common share
|
$
|
0.05
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
(1)
|
Amounts may not sum due to rounding.
|
(2)
|
First quarter of 2016 included the following:
|
•
|
$272.1 million
of proved and unproved property impairments on the Company’s outside-operated Eagle Ford shale assets due to declining commodity prices (see
Note 11 - Fair Value Measurements
)
|
•
|
$69.0 million
net pre-tax loss on divestiture activity related to write-downs on certain non-core assets held for sale (see
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
)
|
•
|
$14.2 million
net derivative gain (see
Note 10 - Derivative Financial Instruments
)
|
•
|
$15.7 million
net gain on the repurchase of a portion of the Company’s Senior Notes (see
Note 5 - Long-Term Debt
)
|
•
|
$50.0 million
net pre-tax gain on divestiture activity related to an increase in fair value less costs to sell on assets held for sale (see
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
)
|
•
|
$163.4 million
net derivative loss (see
Note 10 - Derivative Financial Instruments
)
|
•
|
$11.6 million
of proved and unproved property impairments (see
Note 11 - Fair Value Measurements
)
|
•
|
$22.4 million
net pre-tax gain on divestiture activity upon closing divestitures in the Company’s Rocky Mountain and Permian regions (see
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
)
|
•
|
$28.0 million
net derivative gain (see
Note 10 - Derivative Financial Instruments
)
|
•
|
$151.2 million
of proved and unproved property impairments related primarily to negative performance revisions on the Company’s Powder River Basin assets (see
Note 11 - Fair Value Measurements
)
|
•
|
$33.7 million
net pre-tax gain on divestiture activity upon closing the Raven/Bear Den divestiture (see
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
)
|
•
|
$129.5 million
net derivative loss (see
Note 10 - Derivative Financial Instruments
)
|
(3)
|
First quarter of 2015 included the following:
|
•
|
$67.2 million
of proved and unproved property impairments due to commodity price declines and the Company’s decision to reduce capital invested in the development of certain prospects in its South Texas & Gulf Coast and Permian regions and acreage it no longer intended to develop (see
Note 11 - Fair Value Measurements
)
|
•
|
$16.3 million
of expense relating to an exploratory dry hole
|
•
|
$35.8 million
net pre-tax loss on divestiture activity related to write-downs on certain assets held for sale in the Company’s Mid-Continent region (see
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
)
|
•
|
$154.2 million
net derivative gain (see
Note 10 - Derivative Financial Instruments
)
|
•
|
$18.7 million
of proved and unproved property impairments (see
Note 11 - Fair Value Measurements
)
|
•
|
$71.9 million
net pre-tax gain on divestiture activity upon closing the sale of the Company’s Mid-Continent assets (see
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
)
|
•
|
$80.9 million
net derivative loss (see
Note 10 - Derivative Financial Instruments
)
|
•
|
$16.6 million
net loss on the early extinguishment of the Company’s 2019 Notes (see
Note 5 - Long-Term Debt
)
|
•
|
$62.6 million
of proved and unproved property impairments primarily on legacy assets in the Company’s Rocky Mountain region as a result of the continued decline in commodity strip prices (see
Note 11 - Fair Value Measurements
)
|
•
|
$212.3 million
net derivative gain (see
Note 10 - Derivative Financial Instruments
)
|
•
|
$448.2 million
of proved, unproved, and other property and equipment impairments due to continued commodity price declines, largely impacting the Company’s Powder River Basin program, as well as the Company’s decision to reduce capital invested in the development of its east Texas exploration program in its South Texas & Gulf Coast region (see
Note 11 - Fair Value Measurements
)
|
•
|
$13.8 million
expense relating to exploratory dry holes
|
•
|
$123.3 million
net derivative gain (see
Note 10 - Derivative Financial Instruments
)
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
(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.
|
•
|
provide the Board with explicit authority to cancel, postpone or reschedule a shareholder meeting;
|
•
|
provide the chairman of the meeting with explicit authority to adjourn or recess a shareholder meeting;
|
•
|
clarify the powers of the chairman of the meeting to conduct a shareholder meeting;
|
•
|
provide for additional disclosure requirements for notices of director nominations and shareholder proposals; and
|
•
|
clarify the procedural parameters governing the right of stockholders to take action by written consent.
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
(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 SM Energy or any affiliate of SM Energy. Our Board of Directors approved amendments to the Equity Plan in 2009, 2010, 2013, and 2016 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The number of shares underlying awards granted in
2016
,
2015
, and
2014
under the Equity Plan were
918,509
, 714,949, and
464,641
, respectively.
|
(2)
|
Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the 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. Shares issued under the ESPP totaled
218,135
,
197,214
, and
83,136
in
2016
,
2015
, and
2014
, respectively.
|
(3)
|
RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share 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 share fair value for the outstanding RSUs and PSUs was
$37.39
and $45.53, respectively. Please refer to
Note 7 - Compensation Plans
in Part II, Item 8 of this report for additional discussion.
|
(4)
|
The number of awards vested assumes a
one
multiplier. The final number of shares 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
.
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
Exhibit
Number
|
Description
|
|
|
1.1
|
Underwriting Agreement dated May 7, 2015, among SM Energy Company, and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner, & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of the several underwriters (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on May 8, 2015, and incorporated herein by reference)
|
1.2
|
Underwriting Agreement dated August 8, 2016 by and among SM Energy Company and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
1.3
|
Underwriting Agreement dated August 8, 2016 by and among SM Energy Company and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein (filed as Exhibit 1.2 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
1.4
|
Underwriting Agreement dated September 7, 2016 by and among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities, LLC, and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on September 12, 2016, and incorporated herein by reference)
|
1.5
|
Underwriting Agreement, dated December 1, 2016, by and among SM Energy Company and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on December 7, 2016, and incorporated herein by reference)
|
2.1
|
Acquisition and Development Agreement dated June 29, 2011 between SM Energy Company and Mitsui E&P Texas LP (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
2.2
|
First Amendment to Acquisition and Development Agreement dated October 13, 2011 between SM Energy Company and Mitsui E&P Texas LP (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference)
|
2.3***
|
Purchase and Sale Agreement dated November 4, 2013, among SM Energy Company, EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., and EnerVest Energy Institutional Fund XIII-WIC, L.P. (filed as Exhibit 2.4 to the registrant’s Amendment to the Annual Report on Form 10-K/A filed on May 9, 2014 for the year ended December 31, 2013, and incorporated herein by reference)
|
2.4***
|
Purchase and Sale Agreement dated July 29, 2014 between SM Energy Company and Baytex Energy USA LLC (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, and incorporated herein by reference)
|
2.5
|
Membership Interest Purchase Agreement dated August 8, 2016 between SM Energy Company and Rock Oil Holdings LLC (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on August 8, 2016, and incorporated herein by reference)
|
2.6
|
Purchase and Sale Agreement, dated October 17, 2016, by and between SM Energy Company and QStar LLC (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and incorporated herein by reference)
|
2.7
|
Letter Agreement dated October 17, 2016, by and among SM Energy Company, QStar LLC, and RRP-QStar, LLC (filed as Exhibit 2.2 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and incorporated herein by reference)
|
2.8
|
Purchase and Sale Agreement dated October 17, 2016, by and between SM Energy Company and Oasis Petroleum North America LLC (filed as Exhibit 2.3 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and incorporated herein by reference)
|
3.1
|
Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
|
3.2*
|
Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017
|
4.1
|
Indenture related to the 6.625% Senior Notes due 2019, dated February 7, 2011, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference)
|
4.2
|
Indenture related to the 6.50% Senior Notes due 2021, dated November 8, 2011, by and among SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on November 10, 2011, and incorporated herein by reference)
|
4.3
|
Indenture related to the 6.50% Senior Notes due 2023, dated June 29, 2012, between SM Energy Company, as Issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by reference)
|
4.4
|
Indenture related to the 5.0% Senior Notes due 2024, dated May 20, 2013, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on May 20, 2013, and incorporated herein by reference)
|
4.5
|
Indenture related to the 6.125% Senior Notes due 2022, dated November 17, 2014, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on November 18, 2014, and incorporated herein by reference)
|
4.6
|
Indenture related to senior debt securities of SM Energy Company by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the registrant’s Registration Statement on Form S-3 filed on May 7, 2015 (Registration No. 333-203936) and incorporated herein by reference)
|
4.7
|
2025 Notes Supplemental Indenture (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on May 21, 2015, and incorporated herein by reference)
|
4.8
|
2019 Notes Supplemental Indenture (filed as Exhibit 4.3 to the registrant’s Current Report on Form 8-K filed on May 21, 2015 and incorporated herein by reference)
|
4.9
|
Base Indenture, dated as of May 21, 2015, by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
4.10
|
Second Supplemental Indenture, dated August 12, 2016, by and between SM Energy Company and U.S. Bank, National Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
4.11
|
Third Supplemental Indenture, dated September 12, 2016 by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on September 12, 2016, and incorporated herein by reference)
|
4.12†
|
Equity Incentive Compensation Plan, amended and restated effective May 24, 2016 (filed as Exhibit 4.3 to the registrant’s Form S-8 filed on June 30, 2016, and incorporated herein by reference)
|
4.13*
|
Lock-Up and Registration Rights Agreement, dated December 21, 2016, by and among SM Energy Company, QStar LLC and RRP-QStar, LLC
|
10.1†
|
Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference)
|
10.2†
|
Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference)
|
10.3
|
Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference)
|
10.4
|
Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference)
|
10.5†
|
Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
|
10.6***
|
Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, and incorporated herein by reference)
|
10.7
s
|
Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)
|
10.8†
|
Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit 10.30 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)
|
10.9+
|
SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of November 9, 2010 (filed as Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)
|
10.10
|
Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.11
|
Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company and ETC Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.12
|
Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM Energy Company (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.13†
|
Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.14†
|
Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filed as Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference)
|
10.15†
|
Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filed as Exhibit 10.42 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference)
|
10.16†
|
Equity Incentive Compensation Plan, As Amended as of May 22, 2013 (filed as Annex A to the registrant’s Schedule 14A filed on April 11, 2013, and incorporated herein by reference)
|
10.17
|
Fifth Amended and Restated Credit Agreement dated April 12, 2013, among SM Energy Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April 15, 2013, and incorporated herein by reference)
|
10.18†
|
Form of Performance Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference)
|
10.19†
|
Form of Restricted Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference)
|
10.20†
|
Performance Stock Unit Award Agreement as of July 1, 2016 (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference)
|
10.21†
|
Restricted Stock Unit Award Agreement as of July 1, 2016 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference)
|
10.22†
|
Non-Employee Director Restricted Stock Award Agreement as of May 25, 2016 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference)
|
10.23†
|
SM Energy Company Non-Qualified Deferred Compensation Plan as of March 10, 2014 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on January 24, 2014, and incorporated herein by reference)
|
10.24†
|
Cash Bonus Plan, As Amended and Restated as of February 1, 2014 (filed as Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2013, and incorporated herein by reference)
|
10.25†
|
Section 162(m) Cash Bonus Plan, effective as of May 21, 2014 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 28, 2014, and incorporated herein by reference)
|
10.26*†
|
Summary of Compensation Arrangements for Non-Employee Directors
|
10.27
|
Second Amendment to the Fifth Amended and Restated Credit Agreement dated December 10, 2014, among SM Energy Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on December 16, 2014, and incorporated herein by reference)
|
10.28
|
Third Amendment to Fifth Amended and Restated Credit Agreement, dated May 20, 2015, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2015, and incorporated herein by reference)
|
10.29
|
Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated October 7, 2015, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on October 8, 2015, and incorporated herein by reference)
|
10.30
|
Fifth Amendment to Fifth Amended and Restated Credit Agreement, dated November 11, 2015, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on November 11, 2015, and incorporated herein by reference)
|
10.31
|
Sixth Amendment to Fifth Amended and Restated Credit Agreement, dated April 8, 2016, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April 13, 2016, and incorporated herein by reference)
|
10.32
|
Seventh Amendment to Fifth Amended and Restated Credit Agreement, dated August 8, 2016, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on August 9, 2016, and incorporated herein by reference)
|
10.33
|
Eighth Amendment to Fifth Amended and Restated Credit Agreement, dated September 30, 2016, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on October 6, 2016 and incorporated herein by reference)
|
10.34†
|
Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on October 20, 2015, and incorporated herein by reference)
|
10.35†
|
Amendment No. 3 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2016 (filed as Exhibit 10.29 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2015, and incorporated herein by reference)
|
10.36***
|
Amendment to Amended and Restated Gas Gathering Agreement, effective as of September 1, 2015, by and between SM Energy Company and Regency Field Services LLC (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on September 15, 2015, and incorporated herein by reference)
|
10.37
|
Amendment to Amended and Restated Gas Gathering Agreement, effective as of February 1, 2016, by and between SM Energy Company and ETC Field Services LLC (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on February 22, 2016, and incorporated herein by reference)
|
10.38
|
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and Wells Fargo Bank, National Association (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
10.39
|
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and Bank of America, N.A. (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
10.40
|
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and JPMorgan Chase Bank, National Association (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
10.41
|
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
10.42
|
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and Bank of America, N.A. (filed as Exhibit 10.5 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
10.43
|
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and JPMorgan Chase Bank, National Association (filed as Exhibit 10.6 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
|
12.1*
|
Computation of Ratio of Earnings to Fixed Charges
|
21.1*
|
Subsidiaries of Registrant
|
23.1*
|
Consent of Ernst & Young LLP
|
23.2*
|
Consent of Ryder Scott Company L.P.
|
24.1*
|
Power of Attorney
|
31.1*
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
|
31.2*
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
|
32.1**
|
Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
|
99.1*
|
Ryder Scott Audit Letter
|
101.INS*
|
XBRL Instance Document
|
101.SCH*
|
XBRL Schema Document
|
101.CAL*
|
XBRL Calculation Linkbase Document
|
101.LAB*
|
XBRL Label Linkbase Document
|
101.PRE*
|
XBRL Presentation Linkbase Document
|
101.DEF*
|
XBRL Taxonomy Extension Definition Linkbase Document
|
***
|
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 Securities Exchange Act of 1934.
|
†
|
Exhibit constitutes a management contract or compensatory plan or agreement.
|
s
|
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.
|
+
|
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document.
|
|
|
SM ENERGY COMPANY
|
|
|
|
(Registrant)
|
|
|
|
|
|
Date:
|
February 23, 2017
|
By:
|
/s/ JAVAN D. OTTOSON
|
|
|
|
Javan D. Ottoson
|
|
|
|
President and Chief Executive Officer
|
|
|
|
(Principal Executive Officer)
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ JAVAN D. OTTOSON
|
|
President, Chief Executive Officer, and Director
|
|
February 23, 2017
|
Javan D. Ottoson
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ A. WADE PURSELL
|
|
Executive Vice President and Chief Financial Officer
|
|
February 23, 2017
|
A. Wade Pursell
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ MARK T. SOLOMON
|
|
Vice President - Controller and Assistant Secretary
|
|
February 23, 2017
|
Mark T. Solomon
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ WILLIAM D. SULLIVAN
|
|
Chairman of the Board of Directors
|
|
February 23, 2017
|
William D. Sullivan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ LARRY W. BICKLE
|
|
Director
|
|
February 23, 2017
|
Larry W. Bickle
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/s/ STEPHEN R. BRAND
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Director
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February 23, 2017
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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 23, 2017
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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 23, 2017
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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 23, 2017
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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 23, 2017
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Rose M. Robeson
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Term
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Section
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Advice
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2.5
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Agreement
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Introductory Paragraph
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Common Stock
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Recitals
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Company
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Introductory Paragraph
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Company Notice
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2.1(c)
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Company Underwritten Offering
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2.3
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Demand Request
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2.1(c)
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Effective Date
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2.1(a)
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Letter Agreement
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Recitals
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Lock-Up Period
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3.1
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Material Adverse Effect
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2.2(b)
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Purchase Agreement
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Recitals
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Participating Majority
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2.1(d)
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QStar
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Recitals
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Records
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2.4(l)
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Requesting Holder
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2.1(c)
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Seller Affiliates
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2.7
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Suspension Period
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2.1(f)
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Suspension Notice
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2.5
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Underwritten Shelf Takedown
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2.1(b)
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If to the Company:
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SM Energy Company
775 Sherman Street, Suite 1200 Denver, Colorado 80203
Attention: General Counsel
Facsimile: (303) 864-2598
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If to any Holder, at its address listed on the signature pages hereof.
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With copies to (which shall not constitute notice):
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Vinson & Elkins L.L.P.
1001 Fannin Street, Suite 2500
Houston, Texas 77002
Attention: John B. Connally IV
Facsimile: 713-615-5333
Email: jconnally@velaw.com
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Title:
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Senior Vice President – Business Development and Land
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Address:
QSTAR LLC
6363 Woodway, Suite 750
Houston, Texas 77057
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Copy to:
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QSTAR LLC
6363 Woodway, Suite 750
Houston, Texas 77057
Attn: Gerald Carman
Phone: 713-333-9200
Fax: 713-333-9199
E-mail: gcarman@qstarllc.com
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Address:
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RRP-QSTAR, LLC
767 Fifth Avenue, 16th Floor
New York, New York 10153
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Copy to:
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RRP-QSTAR, LLC
767 Fifth Avenue, 16th Floor
New York, New York 10153
Attn: Legal Department
Phone: 212-610-9032
Fax: 212-610-9001
E-mail: rrpqstar@reservoircap.com
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EnCap Energy Capital Fund IX, L.P.
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Gerald R. Carman
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Mark S. Przywara
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Charles R. Close
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David C. Newman
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Joel E. Saber
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Matthew L. Johnson
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John E. Lodge
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W. Charles O’Donnell
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Cody S. Rodriguez
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Michael E. Tessari
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Thomas E. Mahone
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William L. Brunner
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Megan F. Fitzgerald
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Lisa R. Worthan
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Dusty J. Wells
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Colin M. McGonagill
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Kelly A. Mason
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Larry D. Watkins
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Karl G. Vornsand
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Jeremy L. Goebel
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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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1)
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Annual compensation payable upon election to the Board by the stockholders, valued at $180,000. This resulted in a grant of restricted stock to each non-employee director of 5,645 shares of SM Energy common stock issued on May 25, 2016, under SM Energy's Equity Incentive Compensation Plan. These shares vested on December 31, 2016.
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2)
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A retainer for the Non-Executive Chairman of the Board valued at $85,000. This resulted in a grant of 2,666 shares of SM Energy common stock issued on May 25, 2016, under SM Energy's Equity Incentive Compensation Plan. These shares vested on December 31, 2016.
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3)
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Steven R. Brand, Loren M. Leiker, Rose M. Robeson and William D. Sullivan each elected to receive SM Energy common stock for their retainer, which resulted in a grant of 2,823 shares of SM Energy common stock issued on May 25, 2016, under SM Energy's Equity Incentive Compensation Plan. These shares vested on December 31, 2016. Larry W. Bickle, Ramiro G. Peru and Julio M. Quintana each elected to receive a $90,000 cash payment for their retainer.
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For the Years Ended December 31,
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||||||||||||||||||
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2016
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2015
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2014
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2013
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2012
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(in thousands, except ratios)
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||||||||||||||||||
Pre-tax income (loss) from continuing operations
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$
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(1,201,916
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)
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$
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(722,861
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)
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$
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1,064,699
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$
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278,611
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$
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(83,517
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)
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Add: Fixed charges
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167,600
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155,510
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117,147
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102,758
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77,841
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|||||
Add: Amortization of capitalized interest
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13,905
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9,116
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11,448
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11,784
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9,095
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Less: Capitalized interest
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(17,004
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)
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(25,051
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(16,165
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(10,952
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(12,135
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)
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Earnings before fixed charges
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$
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(1,037,415
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)
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$
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(583,286
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)
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$
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1,177,129
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$
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382,201
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$
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(8,716
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)
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Fixed charges:
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Interest expense
(1)
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$
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148,685
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$
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128,149
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$
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98,554
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$
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89,711
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$
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63,720
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Capitalized interest
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17,004
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25,051
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16,165
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10,952
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12,135
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Interest expense component of rent
(2)
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1,911
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2,310
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2,428
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2,095
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1,986
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Total fixed charges
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$
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167,600
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$
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155,510
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$
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117,147
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$
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102,758
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$
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77,841
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Ratio of earnings to fixed charges
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—
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—
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10.0
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3.7
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—
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|||||
Insufficient coverage
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$
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1,205,015
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$
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738,796
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$
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—
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$
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—
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$
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86,557
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(1)
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Includes amortization of deferred financing costs and discount. For the year ended December 31, 2016, excludes the $10.0 million paid to terminate a second lien facility that was no longer necessary to fund acquisition activity.
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(2)
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Represents a reasonable approximation of the portion of rental expense assumed to be attributable to the interest factor.
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A.
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Wholly-owned subsidiaries of SM Energy Company, a Delaware corporation:
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B.
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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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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, and 333-212359) of SM Energy Company, and
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3.
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Post-Effective Amendment No. 1 to Registration Statement (Form S-3 No. 333-203936) 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.
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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:
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(a)
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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.
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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):
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(a)
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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
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(b)
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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.
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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.
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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:
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(a)
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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.
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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):
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(a)
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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
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(b)
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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.
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/s/ Michael F. Stell
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/s/ James L. Baird
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Michael F. Stell, P.E.
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James L. Baird
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TBPE License No. 56416
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Colorado License No. 41521
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Advising Senior Vice President
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Managing Senior Vice President
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As of December 31, 2016
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Proved
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||||||
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Developed
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Total
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Producing
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Non-Producing
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Undeveloped
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Proved
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Net Reserves of Properties
Audited by Ryder Scott
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Oil/Condensate - MBBL
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40,604
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12
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13,225
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53,841
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Plant Products - MBBL
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55,696
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22
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10,676
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66,394
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Gas – MMCF
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532,930
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153
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52,163
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585,246
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Net Reserves of Properties
Not Audited by Ryder Scott
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Oil/Condensate - MBBL
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7,680
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208
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43,127
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51,015
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Plant Products - MBBL
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2,068
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863
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36,387
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39,318
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Gas – MMCF
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66,866
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9,178
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449,839
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525,883
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Total Net Reserves
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Oil/Condensate - MBBL
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48,284
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220
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56,352
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104,856
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Plant Products - MBBL
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57,764
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|
885
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47,063
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105,712
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Gas – MMCF
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599,796
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9,331
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502,002
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1,111,129
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(1)
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completion intervals which are open at the time of the estimate, but which have not started producing;
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(2)
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wells which were shut-in for market conditions or pipeline connections; or
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(3)
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wells not capable of production for mechanical reasons.
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(i)
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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.
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