Delaware
(State or other jurisdiction
of incorporation or organization)
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41-0518430
(I.R.S. Employer Identification No.)
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1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
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80203
(Zip Code)
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Title of each class
|
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Name of each exchange on which registered
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Common stock, $.01 par value
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New York Stock Exchange
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Large accelerated filer
þ
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Accelerated filer
o
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Non-accelerated filer
o
(Do not check if a smaller reporting company)
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Smaller reporting company
o
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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)
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ITEM
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PAGE
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•
|
Production.
We achieved record levels of production for
2015
. Our average daily production was composed of
52.7
MBbl of oil,
475.7
MMcf of gas, and
44.0
MBbl of NGLs, for an average equivalent production rate of
175.9
MBOE per day, which was
an increase
of
16 percent
from an average of
151.1
MBOE per day in
2014
. Please refer to
Core Operational Areas
below for additional discussion.
|
•
|
Reserves and Capital Investment.
Our estimated proved reserves
decreased
14 percent
to
471.3
MMBOE at
December 31, 2015
, from
547.7
MMBOE at
December 31, 2014
, of which
25.4
MMBOE related to the divestiture of proved reserves. We added
160.6
MMBOE through drilling activities during the year, led by our activities in the Eagle Ford shale and Bakken/Three Forks resource plays. Costs incurred for drilling and exploration activities, excluding acquisitions,
decreased
34 percent
to
$1.4 billion
in
2015
when compared to
2014
. We had strong reserve additions as a result of our success in reducing costs, optimizing completions, and generating better well results in our core development programs; however, these additions were offset by the impact of lower commodity prices. Our proved reserve life
decreased
to
7.3
years in
2015
compared to
9.9
years in
2014
. Please refer to
Reserves
and
Core Operational Areas
below for additional discussion.
|
•
|
Increased Liquidity
. During 2015, we extended the maturity of a portion of our long-term debt by using the proceeds from our issuance of
$500.0 million
in aggregate principal amount of
5.625%
Senior Notes due
2025
to redeem the $350.0 million principal amount of our 6.625% Senior Notes due 2019. The earliest maturity for any of our Senior Notes occurs in 2021. Please refer to
Overview of Liquidity
|
•
|
Divestiture Activity
. During
2015
, we divested a total of
25.4
MMBOE of proved reserves in multiple transactions for aggregate cash proceeds of approximately
$357.9 million
. Our most significant divestiture activity was the sale of our Mid-Continent assets in the second quarter of 2015.
|
•
|
Sustained Low Commodity Prices
. Our financial condition and results of operations are significantly affected by the prices we receive for oil, gas, and NGLs, which can fluctuate dramatically.
|
•
|
Impairments.
We recorded impairment of proved properties expense of
$468.7 million
, abandonment and impairment of unproved properties expense of
$78.6 million
, and impairment of other property and equipment expense of
$49.4 million
for the year ended
December 31, 2015
. These impairments were largely due to commodity price declines, which impacted our Powder River Basin program and certain legacy and non-core assets, as well as our decision to reduce capital invested in the development of our east Texas exploration program in light of the sustained, low commodity price environment.
|
|
South Texas & Gulf Coast
|
|
Rocky
Mountain
|
|
Permian
|
|
Mid-
Continent
(2)
|
|
Total
(1)
|
||||||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
43.6
|
|
|
88.2
|
|
|
13.4
|
|
|
—
|
|
|
145.3
|
|
|||||
Gas (Bcf)
|
1,116.9
|
|
|
102.9
|
|
|
44.2
|
|
|
—
|
|
|
1,264.0
|
|
|||||
NGLs (MMBbl)
|
112.6
|
|
|
2.8
|
|
|
—
|
|
|
—
|
|
|
115.4
|
|
|||||
MMBOE
(1)
|
342.4
|
|
|
108.1
|
|
|
20.8
|
|
|
—
|
|
|
471.3
|
|
|||||
Relative percentage
|
73
|
%
|
|
23
|
%
|
|
4
|
%
|
|
—
|
%
|
|
100
|
%
|
|||||
Proved Developed %
|
50
|
%
|
|
57
|
%
|
|
49
|
%
|
|
—
|
%
|
|
52
|
%
|
|||||
PV-10 (in millions)
(3)
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved Developed
|
$
|
793.4
|
|
|
$
|
667.3
|
|
|
$
|
132.3
|
|
|
$
|
—
|
|
|
$
|
1,593.0
|
|
Proved Undeveloped
|
52.1
|
|
|
129.3
|
|
|
16.1
|
|
|
—
|
|
|
197.5
|
|
|||||
Total Proved
|
$
|
845.5
|
|
|
$
|
796.6
|
|
|
$
|
148.4
|
|
|
$
|
—
|
|
|
$
|
1,790.5
|
|
Relative percentage
|
47
|
%
|
|
45
|
%
|
|
8
|
%
|
|
—
|
%
|
|
100
|
%
|
|||||
Production
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
7.9
|
|
|
9.5
|
|
|
1.8
|
|
|
—
|
|
|
19.2
|
|
|||||
Gas (Bcf)
|
149.5
|
|
|
9.3
|
|
|
5.1
|
|
|
9.7
|
|
|
173.6
|
|
|||||
NGLs (MMBbl)
|
15.7
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
16.1
|
|
|||||
MMBOE
(1)
|
48.5
|
|
|
11.3
|
|
|
2.7
|
|
|
1.7
|
|
|
64.2
|
|
|||||
Avg. Daily Equivalents
(MBOE/d)
|
132.9
|
|
|
31.1
|
|
|
7.4
|
|
|
4.6
|
|
|
175.9
|
|
|||||
Relative percentage
|
75
|
%
|
|
18
|
%
|
|
4
|
%
|
|
3
|
%
|
|
100
|
%
|
|||||
Costs Incurred (in millions)
(4)
|
$
|
765.3
|
|
|
$
|
538.5
|
|
|
$
|
59.4
|
|
|
$
|
9.0
|
|
|
$
|
1,395.0
|
|
(1)
|
Totals may not sum or calculate due to rounding.
|
(2)
|
We divested our Mid-Continent assets in the second quarter of 2015.
|
(3)
|
The standardized measure PV-10 calculation is presented in the
Supplemental Oil and Gas Information
section in Part II, Item 8 of this report. A reconciliation between PV-10 and the after tax amount is shown in the
Reserves
section below.
|
(4)
|
Amounts do not sum to total costs incurred due to certain costs relating to our new venture projects being excluded from the regional table above.
|
|
As of December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Standardized measure of discounted future net cash flows
|
$
|
1,868.9
|
|
|
$
|
5,698.8
|
|
|
$
|
4,009.4
|
|
Add: 10 percent annual discount, net of income taxes
|
1,228.7
|
|
|
3,407.2
|
|
|
2,500.6
|
|
|||
Add: future undiscounted income taxes
|
—
|
|
|
3,511.4
|
|
|
2,722.2
|
|
|||
Undiscounted future net cash flows
|
3,097.6
|
|
|
12,617.4
|
|
|
9,232.2
|
|
|||
Less: 10 percent annual discount without tax effect
|
(1,307.1
|
)
|
|
(5,000.5
|
)
|
|
(3,703.7
|
)
|
|||
PV-10
|
$
|
1,790.5
|
|
|
$
|
7,616.9
|
|
|
$
|
5,528.5
|
|
|
Total
(MMBOE)
|
|
Total proved undeveloped reserves:
|
|
|
Beginning of year
|
260.9
|
|
Revisions of previous estimates
(1)
|
(35.4
|
)
|
Additions from discoveries, extensions, and infill
(2)
|
119.6
|
|
Sales of reserves
|
(4.3
|
)
|
Purchases of minerals in place
|
0.9
|
|
Removed for five-year rule
(3)
|
(79.4
|
)
|
Conversions to proved developed
(4)
|
(35.5
|
)
|
End of year
|
226.8
|
|
(1)
|
Revisions of previous estimates primarily relate to a negative price revision of 57.0 MMBOE due to the decline in commodity prices during 2015. The negative price revision was partially offset by positive performance revisions totaling
21.6
MMBOE primarily in our Eagle Ford shale and Bakken/Three Forks resource plays due to improved performance related to enhanced completions and reductions in operating expenses, which extended the economic lives of the wells.
|
(2)
|
We added
98.6
MMBOE of infill proved undeveloped reserves primarily in our Eagle Ford shale and Bakken/Three Forks resource plays, as well as an additional
21.0
MMBOE of proved undeveloped reserves through extensions and discoveries, primarily in our Eagle Ford shale play.
|
(3)
|
Proved undeveloped reserves were reduced by
79.4
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 implemented during 2015.
|
(4)
|
Conversions of proved undeveloped reserves to proved developed reserves were primarily in our Eagle Ford shale and Bakken/Three Forks resource plays. During
2015
, we incurred approximately
$415 million
on projects associated with reserves booked as proved undeveloped reserves at the end of
2014
. Our 2015 track record and development pace were both below 20 percent. This was due to delineation and testing of an incremental landing zone in our Eagle Ford shale asset, delineation and testing of the Bakken interval, step-out drilling on acreage acquired late in 2014 in our Divide County, North Dakota position, and due to the large reserve volumes associated with drilled and uncompleted wells at year-end 2015. At December 31, 2015, drilled but uncompleted wells represent 59.2 MMBOE of total proved undeveloped reserves. Our multi-year historical track is in excess of 20 percent.
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Net production
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
19.2
|
|
|
16.7
|
|
|
13.9
|
|
|||
Gas (Bcf)
|
173.6
|
|
|
152.9
|
|
|
149.3
|
|
|||
NGLs (MMBbl)
|
16.1
|
|
|
13.0
|
|
|
9.5
|
|
|||
MMBOE
(2)
|
64.2
|
|
|
55.1
|
|
|
48.3
|
|
|||
Eagle Ford net production
(1)
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
7.6
|
|
|
6.9
|
|
|
5.1
|
|
|||
Gas (Bcf)
|
147.2
|
|
|
120.6
|
|
|
97.1
|
|
|||
NGLs (MMBbl)
|
15.6
|
|
|
12.7
|
|
|
9.2
|
|
|||
MMBOE
(2)
|
47.7
|
|
|
39.7
|
|
|
30.5
|
|
|||
Realized price
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
41.49
|
|
|
$
|
80.97
|
|
|
$
|
91.19
|
|
Gas (per Mcf)
|
$
|
2.57
|
|
|
$
|
4.58
|
|
|
$
|
3.93
|
|
NGLs (per Bbl)
|
$
|
15.92
|
|
|
$
|
33.34
|
|
|
$
|
35.95
|
|
Per BOE
|
$
|
23.36
|
|
|
$
|
45.01
|
|
|
$
|
45.50
|
|
Production costs per BOE
|
|
|
|
|
|
||||||
Lease operating expense
|
$
|
3.73
|
|
|
$
|
4.28
|
|
|
$
|
4.49
|
|
Transportation costs
|
$
|
6.02
|
|
|
$
|
6.11
|
|
|
$
|
5.34
|
|
Production taxes
|
$
|
1.13
|
|
|
$
|
2.13
|
|
|
$
|
2.19
|
|
Ad valorem tax expense
|
$
|
0.39
|
|
|
$
|
0.46
|
|
|
$
|
0.33
|
|
(1)
|
In each of the years
2015
,
2014
, and
2013
, 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)
|
Amounts may not calculate due to rounding.
|
|
For the Years Ended December 31,
|
||||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
||
Oil
|
87
|
|
|
56.5
|
|
|
133
|
|
66.1
|
|
154
|
|
75.4
|
Gas
|
272
|
|
|
100.8
|
|
|
476
|
|
165.5
|
|
443
|
|
162.5
|
Non-productive
|
—
|
|
|
—
|
|
|
8
|
|
5.3
|
|
10
|
|
8.5
|
|
359
|
|
|
157.3
|
|
|
617
|
|
236.9
|
|
607
|
|
246.4
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
||
Oil
|
5
|
|
|
3.5
|
|
|
5
|
|
3.0
|
|
6
|
|
5.1
|
Gas
|
1
|
|
|
1.0
|
|
|
7
|
|
4.8
|
|
4
|
|
2.4
|
Non-productive
|
5
|
|
|
4.1
|
|
|
4
|
|
3.3
|
|
1
|
|
0.3
|
|
11
|
|
|
8.6
|
|
|
16
|
|
11.1
|
|
11
|
|
7.8
|
Total
|
370
|
|
|
165.9
|
|
|
633
|
|
248.0
|
|
618
|
|
254.2
|
|
Developed Acres
(1)
|
|
Undeveloped Acres
(2)
|
|
Total
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
South Texas & Gulf Coast:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operated Eagle Ford
|
68,773
|
|
|
66,027
|
|
|
98,178
|
|
|
95,447
|
|
|
166,951
|
|
|
161,474
|
|
Outside-operated Eagle Ford
|
137,348
|
|
|
24,089
|
|
|
100,015
|
|
|
11,869
|
|
|
237,363
|
|
|
35,958
|
|
Other
|
22,083
|
|
|
8,649
|
|
|
204,647
|
|
|
163,988
|
|
|
226,730
|
|
|
172,637
|
|
Rocky Mountain:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
North Rockies:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Divide
|
144,542
|
|
|
90,639
|
|
|
41,450
|
|
|
26,647
|
|
|
185,992
|
|
|
117,286
|
|
Raven
|
48,693
|
|
|
30,466
|
|
|
5,136
|
|
|
1,163
|
|
|
53,829
|
|
|
31,629
|
|
Bear Den
|
21,763
|
|
|
11,233
|
|
|
4,937
|
|
|
1,555
|
|
|
26,700
|
|
|
12,788
|
|
Stateline MT
|
21,102
|
|
|
16,289
|
|
|
12,740
|
|
|
6,718
|
|
|
33,842
|
|
|
23,007
|
|
Other
|
74,921
|
|
|
51,400
|
|
|
298,599
|
|
|
208,365
|
|
|
373,520
|
|
|
259,765
|
|
South Rockies:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
PRB Cretaceous
|
75,035
|
|
|
52,726
|
|
|
193,815
|
|
|
151,655
|
|
|
268,850
|
|
|
204,381
|
|
Other
|
1,556
|
|
|
1,472
|
|
|
126,212
|
|
|
102,642
|
|
|
127,768
|
|
|
104,114
|
|
Permian:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Sweetie Peck
|
13,228
|
|
|
13,177
|
|
|
521
|
|
|
521
|
|
|
13,749
|
|
|
13,698
|
|
Other
|
12,439
|
|
|
7,534
|
|
|
1,831
|
|
|
1,457
|
|
|
14,270
|
|
|
8,991
|
|
Other
|
10,499
|
|
|
10,499
|
|
|
22,604
|
|
|
17,583
|
|
|
33,103
|
|
|
28,082
|
|
Total
(3)
|
651,982
|
|
|
384,200
|
|
|
1,110,685
|
|
|
789,610
|
|
|
1,762,667
|
|
|
1,173,810
|
|
(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
144,100
,
85,300
, and
26,700
net acres are scheduled to expire by
December 31, 2016
,
2017
, and
2018
, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases. Our east Texas acreage, which has been impaired as of December 31, 2015, represents more than 50 percent of the net acres scheduled to expire over the next three years.
|
Region
|
|
Approximate Square Footage Leased
|
|
Corporate
|
|
108,000
|
|
South Texas & Gulf Coast
|
|
64,000
|
|
Rocky Mountain
|
|
44,000
|
|
Permian
|
|
54,000
|
|
Mid-Continent
(1)
|
|
50,000
|
|
Total
|
|
320,000
|
|
(1)
|
During the third quarter of 2015, we vacated our office space in Tulsa, Oklahoma. We have subleased this space through
2019
and our lease expires in 2022.
|
•
|
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 acquisitions;
|
•
|
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 proved 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 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 have an interest may be defective;
|
•
|
the possibility that 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 necessary quantities of natural gas or crude oil to contractual counterparties;
|
•
|
price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
|
•
|
the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our credit facility;
|
•
|
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 debt agreements 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, NGL and natural gas 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 facility 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 facility.
|
•
|
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
|
•
|
suppliers and financial institutions may 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 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; and
|
•
|
changes in government regulations or taxes, including severance and excise taxes.
|
•
|
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, 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
|
|
|
|
|
|
|
||||
December 31, 2014
|
|
$
|
79.89
|
|
|
$
|
29.41
|
|
September 30, 2014
|
|
$
|
90.38
|
|
|
$
|
74.57
|
|
June 30, 2014
|
|
$
|
85.39
|
|
|
$
|
71.00
|
|
March 31, 2014
|
|
$
|
90.22
|
|
|
$
|
69.03
|
|
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, 2015 -
March 31, 2015
|
465
|
|
|
$
|
52.34
|
|
|
—
|
|
|
3,072,184
|
|
April 1, 2015 -
June 30, 2015
|
98
|
|
|
$
|
56.22
|
|
|
—
|
|
|
3,072,184
|
|
July 1, 2015 -
September 30, 2015
|
186,177
|
|
|
$
|
45.50
|
|
|
—
|
|
|
3,072,184
|
|
October 1, 2015 -
October 31, 2015
|
4,988
|
|
|
$
|
35.39
|
|
|
—
|
|
|
3,072,184
|
|
November 1, 2015 -
November 30, 2015
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
December 1, 2015 -
December 31, 2015
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
Total October 1, 2015 -
December 31, 2015
|
4,988
|
|
|
$
|
35.39
|
|
|
—
|
|
|
3,072,184
|
|
Total
|
191,728
|
|
|
$
|
45.27
|
|
|
—
|
|
|
3,072,184
|
|
(1)
|
All shares purchased in
2015
were purchased by us to offset grantee tax withholding obligations that arose upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under the Equity Plan.
|
(2)
|
In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the 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 facility, the indentures governing our Senior Notes and compliance with securities laws. Stock repurchases may be funded with
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
|
(in millions, except per share data)
|
||||||||||||||||||
Total operating revenues and other income
|
$
|
1,557.0
|
|
|
$
|
2,522.3
|
|
|
$
|
2,293.4
|
|
|
$
|
1,505.1
|
|
|
$
|
1,603.3
|
|
Net income (loss)
|
$
|
(447.7
|
)
|
|
$
|
666.1
|
|
|
$
|
170.9
|
|
|
$
|
(54.2
|
)
|
|
$
|
215.4
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
(6.61
|
)
|
|
$
|
9.91
|
|
|
$
|
2.57
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.38
|
|
Diluted
|
$
|
(6.61
|
)
|
|
$
|
9.79
|
|
|
$
|
2.51
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.19
|
|
Total assets at year-end
(1)
|
$
|
5,621.6
|
|
|
$
|
6,483.1
|
|
|
$
|
4,678.1
|
|
|
$
|
4,179.0
|
|
|
$
|
3,784.0
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revolving credit facility
|
$
|
202.0
|
|
|
$
|
166.0
|
|
|
$
|
—
|
|
|
$
|
340.0
|
|
|
$
|
—
|
|
3.50% Senior Convertible Notes, net of debt discount
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
284.7
|
|
Senior Notes, net of unamortized deferred financing costs
(1)
|
$
|
2,316.0
|
|
|
$
|
2,166.4
|
|
|
$
|
1,572.9
|
|
|
$
|
1,079.5
|
|
|
$
|
685.4
|
|
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,
|
||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
Balance Sheet Data (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Total working capital (deficit)
|
$
|
216.5
|
|
|
$
|
(39.6
|
)
|
|
$
|
8.4
|
|
|
$
|
(201.0
|
)
|
|
$
|
(42.6
|
)
|
Total stockholders’ equity
|
$
|
1,852.4
|
|
|
$
|
2,286.7
|
|
|
$
|
1,606.8
|
|
|
$
|
1,414.5
|
|
|
$
|
1,462.9
|
|
Weighted-average common shares outstanding (in thousands)
|
|
|
|
|
|
|
|||||||||||||
Basic
|
67,723
|
|
|
67,230
|
|
|
66,615
|
|
|
65,138
|
|
|
63,755
|
|
|||||
Diluted
|
67,723
|
|
|
68,044
|
|
|
67,998
|
|
|
65,138
|
|
|
67,564
|
|
|||||
Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
145.3
|
|
|
169.7
|
|
|
126.6
|
|
|
92.2
|
|
|
71.7
|
|
|||||
Gas (Bcf)
|
1,264.0
|
|
|
1,466.5
|
|
|
1,189.3
|
|
|
833.4
|
|
|
664.0
|
|
|||||
NGLs (MMBbl)
|
115.4
|
|
|
133.5
|
|
|
103.9
|
|
|
62.3
|
|
|
27.5
|
|
|||||
MMBOE
|
471.3
|
|
|
547.7
|
|
|
428.7
|
|
|
293.4
|
|
|
209.9
|
|
|||||
Production and Operations (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil, gas, and NGL production revenue
|
$
|
1,499.9
|
|
|
$
|
2,481.5
|
|
|
$
|
2,199.6
|
|
|
$
|
1,473.9
|
|
|
$
|
1,332.4
|
|
Oil, gas, and NGL production expense
|
$
|
723.6
|
|
|
$
|
715.9
|
|
|
$
|
597.0
|
|
|
$
|
391.9
|
|
|
$
|
290.1
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
921.0
|
|
|
$
|
767.5
|
|
|
$
|
822.9
|
|
|
$
|
727.9
|
|
|
$
|
511.1
|
|
General and administrative
|
$
|
157.7
|
|
|
$
|
167.1
|
|
|
$
|
149.6
|
|
|
$
|
119.8
|
|
|
$
|
118.5
|
|
Production Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
19.2
|
|
|
16.7
|
|
|
13.9
|
|
|
10.4
|
|
|
8.1
|
|
|||||
Gas (Bcf)
|
173.6
|
|
|
152.9
|
|
|
149.3
|
|
|
120.0
|
|
|
100.3
|
|
|||||
NGLs (MMBbl)
|
16.1
|
|
|
13.0
|
|
|
9.5
|
|
|
6.1
|
|
|
3.5
|
|
|||||
MMBOE
|
64.2
|
|
|
55.1
|
|
|
48.3
|
|
|
36.5
|
|
|
28.3
|
|
|||||
Realized price
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
$
|
41.49
|
|
|
$
|
80.97
|
|
|
$
|
91.19
|
|
|
$
|
85.45
|
|
|
$
|
88.23
|
|
Gas (per Mcf)
|
$
|
2.57
|
|
|
$
|
4.58
|
|
|
$
|
3.93
|
|
|
$
|
2.98
|
|
|
$
|
4.32
|
|
NGLs (per Bbl)
|
$
|
15.92
|
|
|
$
|
33.34
|
|
|
$
|
35.95
|
|
|
$
|
37.61
|
|
|
$
|
53.32
|
|
Expense per BOE
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expense
|
$
|
3.73
|
|
|
$
|
4.28
|
|
|
$
|
4.49
|
|
|
$
|
4.54
|
|
|
$
|
4.97
|
|
Transportation costs
|
$
|
6.02
|
|
|
$
|
6.11
|
|
|
$
|
5.34
|
|
|
$
|
3.81
|
|
|
$
|
3.05
|
|
Production taxes
|
$
|
1.13
|
|
|
$
|
2.13
|
|
|
$
|
2.19
|
|
|
$
|
2.00
|
|
|
$
|
1.90
|
|
Ad valorem tax expense
|
$
|
0.39
|
|
|
$
|
0.46
|
|
|
$
|
0.33
|
|
|
$
|
0.39
|
|
|
$
|
0.33
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
14.34
|
|
|
$
|
13.92
|
|
|
$
|
17.02
|
|
|
$
|
19.95
|
|
|
$
|
18.07
|
|
General and administrative
|
$
|
2.46
|
|
|
$
|
3.03
|
|
|
$
|
3.09
|
|
|
$
|
3.28
|
|
|
$
|
4.19
|
|
Statement of Cash Flow Data (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Provided by operating activities
|
$
|
978.4
|
|
|
$
|
1,456.6
|
|
|
$
|
1,338.5
|
|
|
$
|
922.0
|
|
|
$
|
760.5
|
|
Used in investing activities
|
$
|
(1,144.6
|
)
|
|
$
|
(2,478.7
|
)
|
|
$
|
(1,192.9
|
)
|
|
$
|
(1,457.3
|
)
|
|
$
|
(1,264.9
|
)
|
Provided by financing activities
|
$
|
166.2
|
|
|
$
|
740.0
|
|
|
$
|
130.7
|
|
|
$
|
422.1
|
|
|
$
|
618.5
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
We had record annual production for
2015
. Our average daily production for
2015
was
52.7
MBbls of oil,
475.7
MMcf of gas, and
44.0
MBbls of NGLs, for an average daily equivalent production rate of
175.9
MBOE, compared with
151.1
MBOE in
2014
, an increase of
16 percent
year-over-year. Please refer to the caption
Production Results
below for additional discussion.
|
•
|
At year-end
2015
, we had estimated proved reserves of
471.3
MMBOE, of which
55 percent
were liquids (oil and NGLs) and
52 percent
were characterized as proved developed. We added
160.6
MMBOE through our drilling program, the majority of which related to our activity in the Eagle Ford shale and the Bakken/Three Forks plays, and acquired
1.2
MMBOE. We had a positive performance revision of
47.3
MMBOE due to improved performance in our Eagle Ford shale and Bakken/Three Forks plays related to enhanced completions and reductions in operating expenses, which extended the economic lives of our wells. This upward revision was offset by a
116.5
MMBOE negative price revision due to the decline in commodity prices in 2015 and
79.4
MMBOE of proved undeveloped reserves removed due to the five-year rule. We divested of
25.4
MMBOE of proved reserves primarily in our Mid-Continent region. Our proved reserve life decreased to
7.3
years in 2015 compared to
9.9
years in 2014. 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
$1.9 billion
as of
December 31, 2015
, compared with
$5.7 billion
as of
December 31, 2014
. The standardized measure calculation is presented in the
Supplemental Oil and Gas Information
section located in Part II, Item 8 of this report.
|
•
|
We recorded a net loss of
$447.7 million
, or
$6.61
per diluted share, for the year ended
December 31, 2015
. This compares with net income of
$666.1 million
, or
$9.79
per diluted share, for the year ended
|
•
|
We had net cash flow provided by operating activities of
$978.4 million
for the year ended
December 31, 2015
, compared with
$1.5 billion
for the year ended
December 31, 2014
, which was a decrease of
33 percent
year-over-year. Please refer to
Analysis of cash flow changes between
2015
and
2014
and between
2014
and
2013
below for additional discussion.
|
•
|
Adjusted EBITDAX, a non-GAAP financial measure, for the year ended
December 31, 2015
, was
$1.1 billion
, compared with
$1.6 billion
for the same period in
2014
. Please refer to
Non-GAAP Financial Measures
below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our net income (loss) and net cash provided by operating activities to adjusted EBITDAX.
|
•
|
Costs incurred for oil and gas property acquisition, exploration and development activities for the year ended
December 31, 2015
, totaled
$1.4 billion
. The majority of our drilling and completion costs incurred during this period were in our Eagle Ford shale and Bakken/Three Forks programs. Please refer to the caption
Production Results
below for the number of operated wells completed in these programs during 2015. Additionally, we built an inventory of wells drilled during 2015, which we expect to be completed in future years. Total costs incurred for the same period in 2014 totaled
$2.7 billion
, which included the acquisition of proved and unproved properties in our Gooseneck prospect area and in the Powder River Basin for approximately $561.6 million. Please refer to the caption
Costs Incurred in Oil and Gas Producing Activities
below for additional discussion.
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Crude Oil (per Bbl):
|
|
|
|
|
|
||||||
Average NYMEX price
|
$
|
48.68
|
|
|
$
|
93.03
|
|
|
$
|
97.99
|
|
Realized price, before the effect of derivative settlements
|
$
|
41.49
|
|
|
$
|
80.97
|
|
|
$
|
91.19
|
|
Effect of derivative settlements
|
$
|
18.85
|
|
|
$
|
1.71
|
|
|
$
|
(1.27
|
)
|
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Average NYMEX price (per MMBtu)
|
$
|
2.61
|
|
|
$
|
4.35
|
|
|
$
|
3.73
|
|
Realized price, before the effect of derivative settlements (per Mcf)
|
$
|
2.57
|
|
|
$
|
4.58
|
|
|
$
|
3.93
|
|
Effect of derivative settlements (per Mcf)
(1)
|
$
|
0.71
|
|
|
$
|
(0.18
|
)
|
|
$
|
0.21
|
|
|
|
|
|
|
|
||||||
NGLs (per Bbl):
(2)
|
|
|
|
|
|
||||||
Average OPIS price
|
$
|
19.76
|
|
|
$
|
38.93
|
|
|
$
|
40.44
|
|
Realized price, before the effect of derivative settlements
|
$
|
15.92
|
|
|
$
|
33.34
|
|
|
$
|
35.95
|
|
Effect of derivative settlements
|
$
|
1.69
|
|
|
$
|
0.84
|
|
|
$
|
0.71
|
|
(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 17, 2016
|
|
As of December 31, 2015
|
||||
NYMEX WTI oil (per Bbl)
|
$
|
37.77
|
|
|
$
|
41.34
|
|
NYMEX Henry Hub gas (per MMBtu)
|
$
|
2.30
|
|
|
$
|
2.53
|
|
OPIS NGLs (per Bbl)
|
$
|
16.12
|
|
|
$
|
17.48
|
|
|
South Texas & Gulf Coast
|
|
Rocky
Mountain
|
|
Permian
|
|
Mid-Continent
|
|
Total
(1)
|
|||||
Production:
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MMBbl)
|
7.9
|
|
|
9.5
|
|
|
1.8
|
|
|
—
|
|
|
19.2
|
|
Gas (Bcf)
|
149.5
|
|
|
9.3
|
|
|
5.1
|
|
|
9.7
|
|
|
173.6
|
|
NGLs (MMBbl)
|
15.7
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
16.1
|
|
Equivalent (MMBOE)
(1)
|
48.5
|
|
|
11.3
|
|
|
2.7
|
|
|
1.7
|
|
|
64.2
|
|
Avg. Daily Equivalents (MBOE/d)
|
132.9
|
|
|
31.1
|
|
|
7.4
|
|
|
4.6
|
|
|
175.9
|
|
Relative percentage
|
75
|
%
|
|
18
|
%
|
|
4
|
%
|
|
3
|
%
|
|
100
|
%
|
|
For the Year Ended
|
||
|
December 31, 2015
|
||
|
(in millions)
|
||
Development costs
|
$
|
1,234.1
|
|
Exploration costs
|
132.5
|
|
|
Acquisitions
|
|
||
Proved properties
|
10.0
|
|
|
Unproved properties
|
18.4
|
|
|
Total, including asset retirement obligation
(1)
|
$
|
1,395.0
|
|
(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 for additional discussion on the costs included in this table.
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2015
|
|
2015
|
|
2015
|
|
2015
|
||||||||
|
(in millions, except for production data)
|
||||||||||||||
Production (MMBOE)
|
14.9
|
|
|
16.1
|
|
|
16.5
|
|
|
16.8
|
|
||||
Oil, gas, and NGL production revenue
|
$
|
298.7
|
|
|
$
|
366.6
|
|
|
$
|
441.3
|
|
|
$
|
393.3
|
|
Oil, gas, and NGL production expense
|
$
|
169.2
|
|
|
$
|
184.6
|
|
|
$
|
173.7
|
|
|
$
|
196.2
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
240.0
|
|
|
$
|
243.9
|
|
|
$
|
219.7
|
|
|
$
|
217.4
|
|
Exploration
|
$
|
37.9
|
|
|
$
|
19.7
|
|
|
$
|
25.5
|
|
|
$
|
37.4
|
|
General and administrative
|
$
|
33.6
|
|
|
$
|
37.8
|
|
|
$
|
42.6
|
|
|
$
|
43.6
|
|
Net income (loss)
|
$
|
(340.3
|
)
|
|
$
|
3.1
|
|
|
$
|
(57.5
|
)
|
|
$
|
(53.1
|
)
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2015
|
|
2015
|
|
2015
|
|
2015
|
||||||||
Average net daily production equivalent (MBOE per day)
|
162.1
|
|
|
174.5
|
|
|
181.0
|
|
|
186.4
|
|
||||
Lease operating expense (per BOE)
|
$
|
3.85
|
|
|
$
|
3.86
|
|
|
$
|
3.26
|
|
|
$
|
3.96
|
|
Transportation costs (per BOE)
|
$
|
6.10
|
|
|
$
|
6.27
|
|
|
$
|
5.64
|
|
|
$
|
6.08
|
|
Production taxes as a percent of oil, gas, and NGL production revenue
|
5.1
|
%
|
|
4.2
|
%
|
|
5.2
|
%
|
|
4.8
|
%
|
||||
Ad valorem tax expense (per BOE)
|
$
|
0.38
|
|
|
$
|
0.40
|
|
|
$
|
0.25
|
|
|
$
|
0.52
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
|
$
|
16.10
|
|
|
$
|
15.19
|
|
|
$
|
13.34
|
|
|
$
|
12.96
|
|
General and administrative (per BOE)
|
$
|
2.26
|
|
|
$
|
2.35
|
|
|
$
|
2.59
|
|
|
$
|
2.60
|
|
|
For the Years Ended December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2015/2014
|
|
2014/2013
|
|
2015/2014
|
|
2014/2013
|
||||||||||||||
Net production volumes
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MMBbl)
|
19.2
|
|
|
16.7
|
|
|
13.9
|
|
|
2.6
|
|
|
2.7
|
|
|
15
|
%
|
|
19
|
%
|
|||||||
Gas (Bcf)
|
173.6
|
|
|
152.9
|
|
|
149.3
|
|
|
20.7
|
|
|
3.6
|
|
|
14
|
%
|
|
2
|
%
|
|||||||
NGLs (MMBbl)
|
16.1
|
|
|
13.0
|
|
|
9.5
|
|
|
3.1
|
|
|
3.5
|
|
|
24
|
%
|
|
37
|
%
|
|||||||
Equivalent (MMBOE)
|
64.2
|
|
|
55.1
|
|
|
48.3
|
|
|
9.1
|
|
|
6.8
|
|
|
16
|
%
|
|
14
|
%
|
|||||||
Average net daily production
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MBbl per day)
|
52.7
|
|
|
45.6
|
|
|
38.2
|
|
|
7.0
|
|
|
7.4
|
|
|
15
|
%
|
|
19
|
%
|
|||||||
Gas (MMcf per day)
|
475.7
|
|
|
419.0
|
|
|
409.2
|
|
|
56.7
|
|
|
9.8
|
|
|
14
|
%
|
|
2
|
%
|
|||||||
NGLs (MBbl per day)
|
44.0
|
|
|
35.6
|
|
|
26.0
|
|
|
8.4
|
|
|
9.6
|
|
|
24
|
%
|
|
37
|
%
|
|||||||
Equivalent (MBOE per day)
|
175.9
|
|
|
151.1
|
|
|
132.4
|
|
|
24.9
|
|
|
18.6
|
|
|
16
|
%
|
|
14
|
%
|
|||||||
Oil, gas, and NGL production revenue (in millions)
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Oil production revenue
|
$
|
797.3
|
|
|
$
|
1,348.3
|
|
|
$
|
1,271.5
|
|
|
$
|
(551.0
|
)
|
|
$
|
76.8
|
|
|
(41
|
)%
|
|
6
|
%
|
||
Gas production revenue
|
447.0
|
|
|
699.8
|
|
|
586.3
|
|
|
(252.8
|
)
|
|
113.5
|
|
|
(36
|
)%
|
|
19
|
%
|
|||||||
NGL production revenue
|
255.6
|
|
|
433.4
|
|
|
341.8
|
|
|
(177.8
|
)
|
|
91.6
|
|
|
(41
|
)%
|
|
27
|
%
|
|||||||
Total
|
$
|
1,499.9
|
|
|
$
|
2,481.5
|
|
|
$
|
2,199.6
|
|
|
$
|
(981.6
|
)
|
|
$
|
281.9
|
|
|
(40
|
)%
|
|
13
|
%
|
||
Oil, gas, and NGL production expense (in millions)
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Lease operating expense
|
$
|
239.6
|
|
|
$
|
235.8
|
|
|
$
|
216.9
|
|
|
$
|
3.8
|
|
|
$
|
18.9
|
|
|
2
|
%
|
|
9
|
%
|
||
Transportation costs
|
386.6
|
|
|
337.1
|
|
|
258.2
|
|
|
49.5
|
|
|
78.9
|
|
|
15
|
%
|
|
31
|
%
|
|||||||
Production taxes
|
72.4
|
|
|
117.2
|
|
|
105.8
|
|
|
(44.8
|
)
|
|
11.4
|
|
|
(38
|
)%
|
|
11
|
%
|
|||||||
Ad valorem tax expense
|
25.0
|
|
|
25.8
|
|
|
16.1
|
|
|
(0.8
|
)
|
|
9.7
|
|
|
(3
|
)%
|
|
60
|
%
|
|||||||
Total
|
$
|
723.6
|
|
|
$
|
715.9
|
|
|
$
|
597.0
|
|
|
$
|
7.7
|
|
|
$
|
118.9
|
|
|
1
|
%
|
|
20
|
%
|
||
Realized price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (per Bbl)
|
$
|
41.49
|
|
|
$
|
80.97
|
|
|
$
|
91.19
|
|
|
$
|
(39.48
|
)
|
|
$
|
(10.22
|
)
|
|
(49
|
)%
|
|
(11
|
)%
|
||
Gas (per Mcf)
|
$
|
2.57
|
|
|
$
|
4.58
|
|
|
$
|
3.93
|
|
|
$
|
(2.01
|
)
|
|
$
|
0.65
|
|
|
(44
|
)%
|
|
17
|
%
|
||
NGLs (per Bbl)
|
$
|
15.92
|
|
|
$
|
33.34
|
|
|
$
|
35.95
|
|
|
$
|
(17.42
|
)
|
|
$
|
(2.61
|
)
|
|
(52
|
)%
|
|
(7
|
)%
|
||
Per BOE
|
$
|
23.36
|
|
|
$
|
45.01
|
|
|
$
|
45.50
|
|
|
$
|
(21.65
|
)
|
|
$
|
(0.49
|
)
|
|
(48
|
)%
|
|
(1
|
)%
|
||
Per BOE data
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expense
|
$
|
3.73
|
|
|
$
|
4.28
|
|
|
$
|
4.49
|
|
|
$
|
(0.55
|
)
|
|
$
|
(0.21
|
)
|
|
(13
|
)%
|
|
(5
|
)%
|
||
Transportation costs
|
$
|
6.02
|
|
|
$
|
6.11
|
|
|
$
|
5.34
|
|
|
$
|
(0.09
|
)
|
|
$
|
0.77
|
|
|
(1
|
)%
|
|
14
|
%
|
||
Production taxes
|
$
|
1.13
|
|
|
$
|
2.13
|
|
|
$
|
2.19
|
|
|
$
|
(1.00
|
)
|
|
$
|
(0.06
|
)
|
|
(47
|
)%
|
|
(3
|
)%
|
||
Ad valorem tax expense
|
$
|
0.39
|
|
|
$
|
0.46
|
|
|
$
|
0.33
|
|
|
$
|
(0.07
|
)
|
|
$
|
0.13
|
|
|
(15
|
)%
|
|
39
|
%
|
||
General and administrative
|
$
|
2.46
|
|
|
$
|
3.03
|
|
|
$
|
3.09
|
|
|
$
|
(0.57
|
)
|
|
$
|
(0.06
|
)
|
|
(19
|
)%
|
|
(2
|
)%
|
||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
14.34
|
|
|
$
|
13.92
|
|
|
$
|
17.02
|
|
|
$
|
0.42
|
|
|
$
|
(3.10
|
)
|
|
3
|
%
|
|
(18
|
)%
|
||
Derivative settlement gain
(2)(3)
|
$
|
7.98
|
|
|
$
|
0.22
|
|
|
$
|
0.42
|
|
|
$
|
7.76
|
|
|
$
|
(0.20
|
)
|
|
3,527
|
%
|
|
(48
|
)%
|
||
Earnings per share information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Basic net income (loss) per common share
|
$
|
(6.61
|
)
|
|
$
|
9.91
|
|
|
$
|
2.57
|
|
|
$
|
(16.52
|
)
|
|
$
|
7.34
|
|
|
(167
|
)%
|
|
286
|
%
|
||
Diluted net income (loss) per common share
|
$
|
(6.61
|
)
|
|
$
|
9.79
|
|
|
$
|
2.51
|
|
|
$
|
(16.40
|
)
|
|
$
|
7.28
|
|
|
(168
|
)%
|
|
290
|
%
|
||
Basic weighted-average common shares outstanding (in thousands)
|
67,723
|
|
|
67,230
|
|
|
66,615
|
|
|
493
|
|
|
615
|
|
|
1
|
%
|
|
1
|
%
|
|||||||
Diluted weighted-average common shares outstanding (in thousands)
|
67,723
|
|
|
68,044
|
|
|
67,998
|
|
|
(321
|
)
|
|
46
|
|
|
—
|
%
|
|
—
|
%
|
|
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
|
|
|
Average Net Daily Production Increase (Decrease)
|
|
Production Revenue Increase (Decrease)
|
|
Production Costs Increase (Decrease)
|
|||||
|
(MBOE/d)
|
|
(in millions)
|
|
(in millions)
|
|||||
South Texas & Gulf Coast
|
25.5
|
|
|
$
|
359.1
|
|
|
$
|
104.3
|
|
Rocky Mountain
|
3.6
|
|
|
40.6
|
|
|
31.0
|
|
||
Permian
|
1.0
|
|
|
7.2
|
|
|
(0.5
|
)
|
||
Mid-Continent
|
(11.5
|
)
|
|
(125.0
|
)
|
|
(15.9
|
)
|
||
Total
|
18.6
|
|
|
$
|
281.9
|
|
|
$
|
118.9
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Net gain on divestiture activity
|
$
|
43.0
|
|
|
$
|
0.6
|
|
|
$
|
28.0
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Marketed gas system revenue
|
$
|
9.5
|
|
|
$
|
24.9
|
|
|
$
|
60.0
|
|
Marketed gas system expense
|
$
|
13.9
|
|
|
$
|
24.5
|
|
|
$
|
57.6
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Other operating revenues
|
$
|
4.5
|
|
|
$
|
15.2
|
|
|
$
|
5.8
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Oil, gas, and NGL production expense
|
$
|
723.6
|
|
|
$
|
715.9
|
|
|
$
|
597.0
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
$
|
921.0
|
|
|
$
|
767.5
|
|
|
$
|
822.9
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Summary of Exploration Expense
|
(in millions)
|
||||||||||
Geological and geophysical expenses
|
$
|
7.5
|
|
|
$
|
11.4
|
|
|
$
|
4.3
|
|
Exploratory dry hole
|
36.6
|
|
|
44.4
|
|
|
5.8
|
|
|||
Overhead and other expenses
|
76.5
|
|
|
74.1
|
|
|
64.0
|
|
|||
Total
|
$
|
120.6
|
|
|
$
|
129.9
|
|
|
$
|
74.1
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Impairment of proved properties
|
$
|
468.7
|
|
|
$
|
84.5
|
|
|
$
|
172.6
|
|
Abandonment and impairment of unproved properties
|
$
|
78.6
|
|
|
$
|
75.6
|
|
|
$
|
46.1
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Impairment of other property and equipment
|
$
|
49.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
General and administrative
|
$
|
157.7
|
|
|
$
|
167.1
|
|
|
$
|
149.6
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Change in Net Profits Plan liability
|
$
|
(19.5
|
)
|
|
$
|
(29.8
|
)
|
|
$
|
(21.8
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Derivative gain
|
$
|
(408.8
|
)
|
|
$
|
(583.3
|
)
|
|
$
|
(3.1
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Other operating expenses
|
$
|
30.6
|
|
|
$
|
4.7
|
|
|
$
|
30.1
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Loss on extinguishment of debt
|
$
|
(16.6
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions, except tax rate)
|
||||||||||
Income tax (expense) benefit
|
$
|
275.2
|
|
|
$
|
(398.6
|
)
|
|
$
|
(107.7
|
)
|
Effective tax rate
|
38.1
|
%
|
|
37.4
|
%
|
|
38.6
|
%
|
|
For the Years Ended December 31,
|
|||||||
|
2015
|
|
2014
|
|
2013
|
|||
Weighted-average interest rate
|
6.0
|
%
|
|
6.5
|
%
|
|
6.3
|
%
|
Weighted-average borrowing rate
|
5.5
|
%
|
|
5.9
|
%
|
|
5.7
|
%
|
|
|
For the Years Ended
December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2015/2014
|
|
2014/2013
|
|
2015/2014
|
|
2014/2013
|
||||||||||||
|
|
(in millions)
|
|
|
|
|
||||||||||||||||||||
Net cash provided by operating activities
|
|
$
|
978.4
|
|
|
$
|
1,456.6
|
|
|
$
|
1,338.5
|
|
|
$
|
(478.2
|
)
|
|
$
|
118.1
|
|
|
(33
|
)%
|
|
9
|
%
|
|
|
For the Years Ended
December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2015/2014
|
|
2014/2013
|
|
2015/2014
|
|
2014/2013
|
||||||||||||
|
|
(in millions)
|
|
|
|
|
||||||||||||||||||||
Net cash used in investing activities
|
|
$
|
(1,144.6
|
)
|
|
$
|
(2,478.7
|
)
|
|
$
|
(1,192.9
|
)
|
|
$
|
1,334.1
|
|
|
$
|
(1,285.8
|
)
|
|
(54
|
)%
|
|
108
|
%
|
|
|
For the Years Ended
December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2015/2014
|
|
2014/2013
|
|
2015/2014
|
|
2014/2013
|
||||||||||||
|
|
(in millions)
|
|
|
|
|
||||||||||||||||||||
Net cash provided by financing activities
|
|
$
|
166.2
|
|
|
$
|
740.0
|
|
|
$
|
130.7
|
|
|
$
|
(573.8
|
)
|
|
$
|
609.3
|
|
|
(78
|
)%
|
|
466
|
%
|
Contractual Obligations
|
|
Total
|
|
Less than 1 year
|
|
1-3 years
|
|
3-5 years
|
|
More than 5 years
|
||||||||||
Long-term debt
(1)
|
|
$
|
2,552.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
202.0
|
|
|
$
|
2,350.0
|
|
Interest payments
(2)
|
|
1,101.3
|
|
|
146.9
|
|
|
293.9
|
|
|
285.1
|
|
|
375.4
|
|
|||||
Delivery commitments
(3)
|
|
864.0
|
|
|
87.4
|
|
|
242.8
|
|
|
269.1
|
|
|
264.7
|
|
|||||
Operating leases and contracts
(3)
|
|
100.4
|
|
|
45.3
|
|
|
16.8
|
|
|
14.9
|
|
|
23.4
|
|
|||||
Asset retirement obligations
(4)
|
|
201.0
|
|
|
12.4
|
|
|
45.0
|
|
|
10.8
|
|
|
132.8
|
|
|||||
Other
(5)
|
|
47.2
|
|
|
9.2
|
|
|
14.9
|
|
|
13.5
|
|
|
9.6
|
|
|||||
Total
|
|
$
|
4,865.9
|
|
|
$
|
301.2
|
|
|
$
|
613.4
|
|
|
$
|
795.4
|
|
|
$
|
3,155.9
|
|
(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, 2015
. 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. Inactive wells as of
December 31, 2015
, are shown as an obligation in
2016
due to the substantial uncertainty on the timing of plugging or re-entering these shut-in or temporarily abandoned wells. Please refer to
Note 9 – Asset Retirement Obligations
in Part II, Item 8 of this report for additional discussion regarding our asset retirement obligations.
|
(5)
|
The majority of the amount shown relates to the unfunded portion of our estimated pension liability of
$36.8 million
, for which we have estimated the timing of future payments based on historical annual contribution amounts. We expect to make contributions to our pension plan in
2016
of
$5.8 million
. Other amounts include the undiscounted forecasted payments for the Net Profits Plan. Please refer to
Note 7 – Compensation Plans
and
Note 11 - Fair Value Measurements
in Part II, Item 8 of this report for additional discussion regarding our Net Profits Plan liability.
|
|
For the Years Ended December 31,
|
|||||||
|
2015
|
|
2014
|
|
2013
|
|||
|
MMBOE
|
|
MMBOE
|
|
MMBOE
|
|||
|
Change
|
|
Change
|
|
Change
|
|||
Revisions resulting from performance
|
47.3
|
|
|
11.3
|
|
|
7.2
|
|
Removal of proved undeveloped reserves no longer in our development plan
|
(79.4
|
)
|
|
(4.3
|
)
|
|
(2.8
|
)
|
Revisions resulting from price changes
|
(116.5
|
)
|
|
3.4
|
|
|
0.6
|
|
Total
|
(148.6
|
)
|
|
10.4
|
|
|
5.0
|
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||||||||
|
MMBOE
|
|
Percentage
|
|
MMBOE
|
|
Percentage
|
|
MMBOE
|
|
Percentage
|
||||||
|
Change
|
|
Change
|
|
Change
|
|
Change
|
|
Change
|
|
Change
|
||||||
10% decrease in SEC pricing
|
(107.6
|
)
|
|
(23
|
)%
|
|
(9.6
|
)
|
|
(2
|
)%
|
|
(9.8
|
)
|
|
(2
|
)%
|
10% decrease in proved undeveloped reserves
|
(22.7
|
)
|
|
(5
|
)%
|
|
(26.1
|
)
|
|
(5
|
)%
|
|
(22.0
|
)
|
|
(5
|
)%
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
Net income (loss) (GAAP)
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
|
$
|
170,935
|
|
|
|
Interest expense
|
128,149
|
|
|
98,554
|
|
|
89,711
|
|
|||
|
Other non-operating (income) expense, net
|
(649
|
)
|
|
2,561
|
|
|
(67
|
)
|
|||
|
Income tax expense (benefit)
|
(275,151
|
)
|
|
398,648
|
|
|
107,676
|
|
|||
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
921,009
|
|
|
767,532
|
|
|
822,872
|
|
|||
|
Exploration
(1)
|
113,158
|
|
|
122,577
|
|
|
65,888
|
|
|||
|
Impairment of proved properties
|
468,679
|
|
|
84,480
|
|
|
172,641
|
|
|||
|
Abandonment and impairment of unproved properties
|
78,643
|
|
|
75,638
|
|
|
46,105
|
|
|||
|
Impairment of other property and equipment
|
49,369
|
|
|
—
|
|
|
—
|
|
|||
|
Stock-based compensation expense
|
27,467
|
|
|
32,694
|
|
|
32,347
|
|
|||
|
Derivative gain
|
(408,831
|
)
|
|
(583,264
|
)
|
|
(3,080
|
)
|
|||
|
Derivative settlement gain
(2)
|
512,566
|
|
|
12,615
|
|
|
22,062
|
|
|||
|
Change in Net Profits Plan liability
|
(19,525
|
)
|
|
(29,849
|
)
|
|
(21,842
|
)
|
|||
|
Net gain on divestiture activity
|
(43,031
|
)
|
|
(646
|
)
|
|
(27,974
|
)
|
|||
|
Loss on extinguishment of debt
|
16,578
|
|
|
—
|
|
|
—
|
|
|||
|
Other, net
|
4,054
|
|
|
—
|
|
|
—
|
|
|||
Adjusted EBITDAX (Non-GAAP)
|
1,124,775
|
|
|
1,647,591
|
|
|
1,477,274
|
|
||||
|
Interest expense
|
(128,149
|
)
|
|
(98,554
|
)
|
|
(89,711
|
)
|
|||
|
Other non-operating income (expense), net
|
649
|
|
|
(2,561
|
)
|
|
67
|
|
|||
|
Income tax (expense) benefit
|
275,151
|
|
|
(398,648
|
)
|
|
(107,676
|
)
|
|||
|
Exploration
(1)
|
(113,158
|
)
|
|
(122,577
|
)
|
|
(65,888
|
)
|
|||
|
Exploratory dry hole expense
|
36,612
|
|
|
44,427
|
|
|
5,846
|
|
|||
|
Amortization of deferred financing costs
|
7,710
|
|
|
6,146
|
|
|
5,390
|
|
|||
|
Deferred income taxes
|
(276,722
|
)
|
|
397,780
|
|
|
105,555
|
|
|||
|
Plugging and abandonment
|
(7,496
|
)
|
|
(8,796
|
)
|
|
(9,946
|
)
|
|||
|
Loss on extinguishment of debt
|
(12,455
|
)
|
|
—
|
|
|
—
|
|
|||
|
Other, net
|
9,707
|
|
|
1,069
|
|
|
2,775
|
|
|||
|
Changes in current assets and liabilities
|
61,728
|
|
|
(9,302
|
)
|
|
14,828
|
|
|||
Net cash provided by operating activities (GAAP)
|
$
|
978,352
|
|
|
$
|
1,456,575
|
|
|
$
|
1,338,514
|
|
(2)
|
Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include a
$15.3 million
gain and
$5.6 million
gain on the early settlement of futures contracts during the second quarter of 2015 and first quarter of 2014, respectively, as a result of divesting our Mid-Continent assets.
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
ASSETS
|
|
|
(as adjusted)
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
18
|
|
|
$
|
120
|
|
Accounts receivable (note 2)
|
134,124
|
|
|
322,630
|
|
||
Derivative asset
|
367,710
|
|
|
402,668
|
|
||
Prepaid expenses and other
|
17,137
|
|
|
19,625
|
|
||
Total current assets
|
518,989
|
|
|
745,043
|
|
||
|
|
|
|
||||
Property and equipment (successful efforts method):
|
|
|
|
||||
Proved oil and gas properties
|
7,606,405
|
|
|
7,348,436
|
|
||
Less - accumulated depletion, depreciation, and amortization
|
(3,481,836
|
)
|
|
(3,233,012
|
)
|
||
Unproved oil and gas properties
|
284,538
|
|
|
532,498
|
|
||
Wells in progress
|
387,432
|
|
|
503,734
|
|
||
Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $0 and $22,482, respectively
|
641
|
|
|
17,891
|
|
||
Other property and equipment, net of accumulated depreciation of $32,956 and $37,079, respectively
|
153,100
|
|
|
334,356
|
|
||
Total property and equipment, net
|
4,950,280
|
|
|
5,503,903
|
|
||
|
|
|
|
||||
Noncurrent assets:
|
|
|
|
||||
Derivative asset
|
120,701
|
|
|
189,540
|
|
||
Other noncurrent assets
|
31,673
|
|
|
44,659
|
|
||
Total other noncurrent assets
|
152,374
|
|
|
234,199
|
|
||
Total Assets
|
$
|
5,621,643
|
|
|
$
|
6,483,145
|
|
|
|
|
|
||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses (note 2)
|
$
|
302,517
|
|
|
$
|
640,684
|
|
Derivative liability
|
8
|
|
|
—
|
|
||
Deferred tax liability
|
—
|
|
|
142,976
|
|
||
Other current liabilities
|
—
|
|
|
1,000
|
|
||
Total current liabilities
|
302,525
|
|
|
784,660
|
|
||
|
|
|
|
||||
Noncurrent liabilities:
|
|
|
|
||||
Revolving credit facility
|
202,000
|
|
|
166,000
|
|
||
Senior Notes, net of unamortized deferred financing costs (note 5)
|
2,315,970
|
|
|
2,166,445
|
|
||
Asset retirement obligation
|
137,525
|
|
|
120,867
|
|
||
Net Profits Plan liability
|
7,611
|
|
|
27,136
|
|
||
Deferred income taxes
|
758,279
|
|
|
891,681
|
|
||
Derivative liability
|
—
|
|
|
70
|
|
||
Other noncurrent liabilities
|
45,332
|
|
|
39,631
|
|
||
Total noncurrent liabilities
|
3,466,717
|
|
|
3,411,830
|
|
||
|
|
|
|
||||
Commitments and contingencies (note 6)
|
|
|
|
||||
|
|
|
|
||||
Stockholders
’
equity:
|
|
|
|
||||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 68,075,700 and 67,463,060 shares, respectively
|
681
|
|
|
675
|
|
||
Additional paid-in capital
|
305,607
|
|
|
283,295
|
|
||
Retained earnings
|
1,559,515
|
|
|
2,013,997
|
|
||
Accumulated other comprehensive loss
|
(13,402
|
)
|
|
(11,312
|
)
|
||
Total stockholders
’
equity
|
1,852,401
|
|
|
2,286,655
|
|
||
Total Liabilities and Stockholders
’
Equity
|
$
|
5,621,643
|
|
|
$
|
6,483,145
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Operating revenues:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production revenue
|
$
|
1,499,905
|
|
|
$
|
2,481,544
|
|
|
$
|
2,199,550
|
|
Net gain on divestiture activity (note 3)
|
43,031
|
|
|
646
|
|
|
27,974
|
|
|||
Marketed gas system revenue
|
9,485
|
|
|
24,897
|
|
|
60,039
|
|
|||
Other operating revenues
|
4,544
|
|
|
15,220
|
|
|
5,811
|
|
|||
Total operating revenues and other income
|
1,556,965
|
|
|
2,522,307
|
|
|
2,293,374
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production expense
|
723,633
|
|
|
715,878
|
|
|
597,045
|
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
921,009
|
|
|
767,532
|
|
|
822,872
|
|
|||
Exploration
|
120,569
|
|
|
129,857
|
|
|
74,104
|
|
|||
Impairment of proved properties
|
468,679
|
|
|
84,480
|
|
|
172,641
|
|
|||
Abandonment and impairment of unproved properties
|
78,643
|
|
|
75,638
|
|
|
46,105
|
|
|||
Impairment of other property and equipment
|
49,369
|
|
|
—
|
|
|
—
|
|
|||
General and administrative
|
157,668
|
|
|
167,103
|
|
|
149,551
|
|
|||
Change in Net Profits Plan liability
|
(19,525
|
)
|
|
(29,849
|
)
|
|
(21,842
|
)
|
|||
Derivative gain
|
(408,831
|
)
|
|
(583,264
|
)
|
|
(3,080
|
)
|
|||
Marketed gas system expense
|
13,922
|
|
|
24,460
|
|
|
57,647
|
|
|||
Other operating expenses
|
30,612
|
|
|
4,658
|
|
|
30,076
|
|
|||
Total operating expenses
|
2,135,748
|
|
|
1,356,493
|
|
|
1,925,119
|
|
|||
Income (loss) from operations
|
(578,783
|
)
|
|
1,165,814
|
|
|
368,255
|
|
|||
Non-operating income (expense):
|
|
|
|
|
|
||||||
Other, net
|
649
|
|
|
(2,561
|
)
|
|
67
|
|
|||
Interest expense
|
(128,149
|
)
|
|
(98,554
|
)
|
|
(89,711
|
)
|
|||
Loss on extinguishment of debt
|
(16,578
|
)
|
|
—
|
|
|
—
|
|
|||
Income (loss) before income taxes
|
(722,861
|
)
|
|
1,064,699
|
|
|
278,611
|
|
|||
Income tax (expense) benefit
|
275,151
|
|
|
(398,648
|
)
|
|
(107,676
|
)
|
|||
Net income (loss)
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
|
$
|
170,935
|
|
Basic weighted-average common shares outstanding
|
67,723
|
|
|
67,230
|
|
|
66,615
|
|
|||
Diluted weighted-average common shares outstanding
|
67,723
|
|
|
68,044
|
|
|
67,998
|
|
|||
Basic net income (loss) per common share
|
$
|
(6.61
|
)
|
|
$
|
9.91
|
|
|
$
|
2.57
|
|
Diluted net income (loss) per common share
|
$
|
(6.61
|
)
|
|
$
|
9.79
|
|
|
$
|
2.51
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Net income (loss)
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
|
$
|
170,935
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
||||||
Reclassification to earnings
(1)
|
—
|
|
|
—
|
|
|
1,115
|
|
|||
Pension liability adjustment
(2)
|
(2,090
|
)
|
|
(5,896
|
)
|
|
2,483
|
|
|||
Total other comprehensive income (loss), net of tax
|
(2,090
|
)
|
|
(5,896
|
)
|
|
3,598
|
|
|||
Total comprehensive income (loss)
|
$
|
(449,800
|
)
|
|
$
|
660,155
|
|
|
$
|
174,533
|
|
(1)
|
Reclassification from accumulated other comprehensive loss related to de-designated hedges. Refer to
Note 10 - Derivative Financial Instruments
for further information.
|
(2)
|
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, 2013
|
66,245,816
|
|
|
$
|
662
|
|
|
$
|
233,642
|
|
|
(50,581
|
)
|
|
$
|
(1,221
|
)
|
|
$
|
1,190,397
|
|
|
$
|
(9,014
|
)
|
|
$
|
1,414,466
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
170,935
|
|
|
—
|
|
|
170,935
|
|
||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,598
|
|
|
3,598
|
|
||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,663
|
)
|
|
—
|
|
|
(6,663
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
77,427
|
|
|
1
|
|
|
3,671
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,672
|
|
||||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
|
526,852
|
|
|
5
|
|
|
(16,225
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16,220
|
)
|
||||||
Issuance of common stock upon stock option exercises
|
228,758
|
|
|
3
|
|
|
3,183
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,186
|
|
||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
31,949
|
|
|
28,169
|
|
|
398
|
|
|
—
|
|
|
—
|
|
|
32,347
|
|
||||||
Other income tax benefit
|
—
|
|
|
—
|
|
|
1,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,500
|
|
||||||
Balances, December 31, 2013
|
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
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(447,710
|
)
|
|
666,051
|
|
|
170,935
|
|
||
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Net gain on divestiture activity
|
(43,031
|
)
|
|
(646
|
)
|
|
(27,974
|
)
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
921,009
|
|
|
767,532
|
|
|
822,872
|
|
|||
Exploratory dry hole expense
|
36,612
|
|
|
44,427
|
|
|
5,846
|
|
|||
Impairment of proved properties
|
468,679
|
|
|
84,480
|
|
|
172,641
|
|
|||
Abandonment and impairment of unproved properties
|
78,643
|
|
|
75,638
|
|
|
46,105
|
|
|||
Impairment of other property and equipment
|
49,369
|
|
|
—
|
|
|
—
|
|
|||
Stock-based compensation expense
|
27,467
|
|
|
32,694
|
|
|
32,347
|
|
|||
Change in Net Profits Plan liability
|
(19,525
|
)
|
|
(29,849
|
)
|
|
(21,842
|
)
|
|||
Derivative gain
|
(408,831
|
)
|
|
(583,264
|
)
|
|
(3,080
|
)
|
|||
Derivative settlement gain
|
512,566
|
|
|
12,615
|
|
|
22,062
|
|
|||
Amortization of deferred financing costs
|
7,710
|
|
|
6,146
|
|
|
5,390
|
|
|||
Non-cash loss on extinguishment of debt
|
4,123
|
|
|
—
|
|
|
—
|
|
|||
Deferred income taxes
|
(276,722
|
)
|
|
397,780
|
|
|
105,555
|
|
|||
Plugging and abandonment
|
(7,496
|
)
|
|
(8,796
|
)
|
|
(9,946
|
)
|
|||
Other, net
|
13,761
|
|
|
1,069
|
|
|
2,775
|
|
|||
Changes in current assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
140,200
|
|
|
24,088
|
|
|
(79,398
|
)
|
|||
Prepaid expenses and other
|
2,563
|
|
|
(1,822
|
)
|
|
98
|
|
|||
Accounts payable and accrued expenses
|
(86,267
|
)
|
|
9,466
|
|
|
91,516
|
|
|||
Accrued derivative settlements
|
5,232
|
|
|
(41,034
|
)
|
|
2,612
|
|
|||
Net cash provided by operating activities
|
978,352
|
|
|
1,456,575
|
|
|
1,338,514
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Net proceeds from the sale of oil and gas properties
|
357,938
|
|
|
43,858
|
|
|
424,849
|
|
|||
Capital expenditures
|
(1,493,608
|
)
|
|
(1,974,798
|
)
|
|
(1,553,536
|
)
|
|||
Acquisition of proved and unproved oil and gas properties
|
(7,984
|
)
|
|
(544,553
|
)
|
|
(61,603
|
)
|
|||
Other, net
|
(985
|
)
|
|
(3,256
|
)
|
|
(2,613
|
)
|
|||
Net cash used in investing activities
|
(1,144,639
|
)
|
|
(2,478,749
|
)
|
|
(1,192,903
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from credit facility
|
1,872,500
|
|
|
1,285,500
|
|
|
1,203,000
|
|
|||
Repayment of credit facility
|
(1,836,500
|
)
|
|
(1,119,500
|
)
|
|
(1,543,000
|
)
|
|||
Debt issuance costs related to credit facility
|
—
|
|
|
(3,388
|
)
|
|
(3,444
|
)
|
|||
Net proceeds from Senior Notes
|
490,951
|
|
|
589,991
|
|
|
490,185
|
|
|||
Repayment of Senior Notes
|
(350,000
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from sale of common stock
|
4,844
|
|
|
4,877
|
|
|
6,858
|
|
|||
Dividends paid
|
(6,772
|
)
|
|
(6,723
|
)
|
|
(6,663
|
)
|
|||
Net share settlement from issuance of stock awards
|
(8,678
|
)
|
|
(10,624
|
)
|
|
(16,220
|
)
|
|||
Other, net
|
(160
|
)
|
|
(87
|
)
|
|
(5
|
)
|
|||
Net cash provided by financing activities
|
166,185
|
|
|
740,046
|
|
|
130,711
|
|
|||
|
|
|
|
|
|
||||||
Net change in cash and cash equivalents
|
(102
|
)
|
|
(282,128
|
)
|
|
276,322
|
|
|||
Cash and cash equivalents at beginning of period
|
120
|
|
|
282,248
|
|
|
5,926
|
|
|||
Cash and cash equivalents at end of period
|
$
|
18
|
|
|
$
|
120
|
|
|
$
|
282,248
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Cash paid for interest, net of capitalized interest
|
$
|
126,988
|
|
|
$
|
89,145
|
|
|
$
|
70,702
|
|
|
|
|
|
|
|
||||||
Net cash paid (refunded) for income taxes
|
$
|
1,630
|
|
|
$
|
1,936
|
|
|
$
|
(204
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands, except per share amounts)
|
||||||||||
Net income (loss)
|
$
|
(447,710
|
)
|
|
$
|
666,051
|
|
|
$
|
170,935
|
|
Basic weighted-average common shares outstanding
|
67,723
|
|
|
67,230
|
|
|
66,615
|
|
|||
Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs
(1)
|
—
|
|
|
814
|
|
|
1,383
|
|
|||
Diluted weighted-average common shares outstanding
|
67,723
|
|
|
68,044
|
|
|
67,998
|
|
|||
Basic net income (loss) per common share
|
$
|
(6.61
|
)
|
|
$
|
9.91
|
|
|
$
|
2.57
|
|
Diluted net income (loss) per common share
|
$
|
(6.61
|
)
|
|
$
|
9.79
|
|
|
$
|
2.51
|
|
(1)
|
For the year ended December 31, 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share.
|
|
Derivative Adjustments
(1)
|
|
Pension Liability Adjustments
|
||||
|
(in thousands)
|
||||||
For the year ended December 31, 2013
|
|
|
|
||||
Net actuarial gain
|
|
|
$
|
2,766
|
|
||
Reclassification to earnings
|
$
|
1,777
|
|
|
1,239
|
|
|
Tax expense
|
(662
|
)
|
|
(1,522
|
)
|
||
Income, net of tax
|
$
|
1,115
|
|
|
$
|
2,483
|
|
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
|
)
|
(1)
|
As of December 31, 2013, all commodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified into earnings from AOCL.
|
|
As of
|
||||||
|
December 31, 2014
|
||||||
|
As Reported
|
|
As Adjusted
|
||||
|
(in thousands)
|
||||||
Other noncurrent assets
|
$
|
78,214
|
|
|
$
|
44,659
|
|
Total other noncurrent assets
|
$
|
267,754
|
|
|
$
|
234,199
|
|
Total Assets
|
$
|
6,516,700
|
|
|
$
|
6,483,145
|
|
Senior Notes
|
$
|
2,200,000
|
|
|
N/A
|
|
|
Senior Notes, net of unamortized deferred financing costs
|
N/A
|
|
|
$
|
2,166,445
|
|
|
Total noncurrent liabilities
|
$
|
3,445,385
|
|
|
$
|
3,411,830
|
|
Total Liabilities and Stockholders’ Equity
|
$
|
6,516,700
|
|
|
$
|
6,483,145
|
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Accrued oil, gas, and NGL production revenue
|
$
|
58,256
|
|
|
$
|
180,250
|
|
Amounts due from joint interest owners
|
22,269
|
|
|
58,347
|
|
||
Accrued derivative settlements
|
34,579
|
|
|
39,811
|
|
||
State severance tax refunds
|
12,072
|
|
|
24,394
|
|
||
Other
|
6,948
|
|
|
19,828
|
|
||
Total accounts receivable
|
$
|
134,124
|
|
|
$
|
322,630
|
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Accrued capital expenditures
|
$
|
97,355
|
|
|
$
|
357,156
|
|
Revenue and severance tax payable
|
44,387
|
|
|
63,779
|
|
||
Accrued lease operating expense
|
21,943
|
|
|
34,822
|
|
||
Accrued property taxes
|
14,078
|
|
|
15,059
|
|
||
Accrued compensation
|
41,154
|
|
|
56,279
|
|
||
Accrued interest
|
34,378
|
|
|
40,786
|
|
||
Other
|
49,222
|
|
|
72,803
|
|
||
Total accounts payable and accrued expenses
|
$
|
302,517
|
|
|
$
|
640,684
|
|
•
|
Mid-Continent Divestiture.
During the second quarter of 2015, the Company divested its Mid-Continent assets in multiple transactions for total divestiture proceeds of
$316.8 million
and a final net gain of
$108.4 million
. Certain of these assets were written down by
$30.0 million
to reflect fair value less estimated costs to sell upon reclassification to assets held for sale as of March 31, 2015. This write-down is reflected in the final net gain of
$108.4 million
discussed above.
|
•
|
Permian Divestiture.
During the fourth quarter of 2015, the Company divested certain non-core assets in its Permian region. Total divestiture proceeds were
$25.1 million
and the estimated total net gain on this divestiture was
$2.4 million
. This divestiture is subject to normal post-closing adjustments, which are expected to occur in the first half of 2016.
|
•
|
Rocky Mountain Divestiture.
During the second quarter of 2014, the Company divested certain non-core assets in the Montana portion of the Williston Basin. Total divestiture proceeds were
$50.1 million
and the final net gain on this divestiture was
$26.9 million
.
|
•
|
Mid-Continent Divestitures.
In December 2013, the Company divested of certain non-strategic assets located in its Mid-Continent region, with the largest transaction being the sale of the Company’s Anadarko Basin assets. Total divestiture proceeds were
$368.5 million
and the final net gain on these divestitures was
$25.3 million
. A portion of one transaction was structured to qualify as a like-kind exchange under Section 1031 of the IRC.
|
•
|
Rocky Mountain Divestitures
. During 2013, the Company divested of certain non-strategic assets located in its Rocky Mountain region. Final divestiture proceeds for these divestitures were
$57.1 million
and the final net gain was
$13.2 million
.
|
•
|
Permian Divestiture
. In December 2013, the Company divested of certain non-strategic assets located in its Permian region. Final divestiture proceeds were
$14.0 million
and the final net loss was
$7.0 million
.
|
•
|
Gooseneck Property Acquisitions
|
|
Acquisition #1
|
|
Acquisition #2
|
||||
|
As of September 24, 2014
|
|
As of October 15, 2014
|
||||
Purchase Price
|
(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.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
Current portion of income tax expense
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
|
1,571
|
|
|
868
|
|
|
2,121
|
|
|||
Deferred portion of income tax expense (benefit)
|
|
(276,722
|
)
|
|
397,780
|
|
|
105,555
|
|
|||
Total income tax expense (benefit)
|
|
$
|
(275,151
|
)
|
|
$
|
398,648
|
|
|
$
|
107,676
|
|
Effective tax rate
|
|
38.1
|
%
|
|
37.4
|
%
|
|
38.6
|
%
|
|
|
As of December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in thousands)
|
||||||
Deferred tax liabilities:
|
|
|
|
|
||||
Oil and gas properties
|
|
$
|
854,029
|
|
|
$
|
1,029,424
|
|
Derivative asset
|
|
179,543
|
|
|
220,437
|
|
||
Other
|
|
1,233
|
|
|
4,475
|
|
||
Total deferred tax liabilities
|
|
1,034,805
|
|
|
1,254,336
|
|
||
Deferred tax assets:
|
|
|
|
|
|
|
||
Federal and state tax net operating loss carryovers
|
|
244,942
|
|
|
184,447
|
|
||
Stock compensation
|
|
14,529
|
|
|
16,763
|
|
||
Other liabilities
|
|
27,449
|
|
|
25,715
|
|
||
Total deferred tax assets
|
|
286,920
|
|
|
226,925
|
|
||
Valuation allowance
|
|
(10,394
|
)
|
|
(7,246
|
)
|
||
Net deferred tax assets
|
|
276,526
|
|
|
219,679
|
|
||
Total net deferred tax liabilities
(1)
|
|
$
|
758,279
|
|
|
$
|
1,034,657
|
|
Current federal income tax refundable
|
|
$
|
5,378
|
|
|
$
|
4,734
|
|
Current state income tax refundable
|
|
$
|
65
|
|
|
$
|
—
|
|
Current state income tax payable
|
|
$
|
—
|
|
|
$
|
25
|
|
(1)
|
All deferred tax liabilities and assets as of December 31, 2015, are classified as noncurrent on the accompanying balance sheets upon the Company’s adoption of ASU 2015-17 on a prospective basis. Prior year amounts have not been restated. Please refer to the caption
Recently Issued Accounting Standards
in
Note 1 - Summary of Significant Accounting Policies
for additional discussion.
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Federal statutory tax expense (benefit)
|
$
|
(253,001
|
)
|
|
$
|
372,644
|
|
|
$
|
97,514
|
|
Increase (decrease) in tax resulting from:
|
|
|
|
|
|
||||||
State tax expense (benefit) (net of federal benefit)
|
(21,583
|
)
|
|
21,350
|
|
|
9,400
|
|
|||
Change in valuation allowance
|
3,148
|
|
|
2,245
|
|
|
(314
|
)
|
|||
Research and development credit
|
(1,971
|
)
|
|
—
|
|
|
—
|
|
|||
Other
|
(1,744
|
)
|
|
2,409
|
|
|
1,076
|
|
|||
Income tax expense (benefit)
|
$
|
(275,151
|
)
|
|
$
|
398,648
|
|
|
$
|
107,676
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
1,582
|
|
|
$
|
2,358
|
|
|
$
|
2,278
|
|
Additions for tax positions of prior years
|
1,200
|
|
|
140
|
|
|
80
|
|
|||
Settlements
|
—
|
|
|
(916
|
)
|
|
—
|
|
|||
Ending balance
|
$
|
2,782
|
|
|
$
|
1,582
|
|
|
$
|
2,358
|
|
Borrowing Base Utilization Percentage
|
|
<25%
|
|
≥25% <50%
|
|
≥50% <75%
|
|
≥75% <90%
|
|
≥90%
|
|||||
Eurodollar Loans
|
|
1.250
|
%
|
|
1.500
|
%
|
|
1.750
|
%
|
|
2.000
|
%
|
|
2.250
|
%
|
ABR Loans or Swingline Loans
|
|
0.250
|
%
|
|
0.500
|
%
|
|
0.750
|
%
|
|
1.000
|
%
|
|
1.250
|
%
|
Commitment Fee Rate
|
|
0.300
|
%
|
|
0.300
|
%
|
|
0.350
|
%
|
|
0.375
|
%
|
|
0.375
|
%
|
|
As of February 17, 2016
|
|
As of December 31, 2015
|
|
As of December 31, 2014
|
||||||
|
(in thousands)
|
||||||||||
Credit facility balance
(1)
|
$
|
243,000
|
|
|
$
|
202,000
|
|
|
$
|
166,000
|
|
Letters of credit
(2)
|
$
|
200
|
|
|
$
|
200
|
|
|
$
|
808
|
|
Available borrowing capacity
|
$
|
1,256,800
|
|
|
$
|
1,297,800
|
|
|
$
|
1,333,192
|
|
(1)
|
Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance.
|
(2)
|
Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.
|
|
As of December 31,
|
||||||||||||||||||||||
|
2015
|
|
2014
(1)
|
||||||||||||||||||||
|
Senior Notes
|
|
Unamortized Deferred Financing Costs
|
|
Senior Notes, Net of Unamortized Deferred Financing Costs
|
|
Senior Notes
|
|
Unamortized Deferred Financing Costs
|
|
Senior Notes, Net of Unamortized Deferred Financing Costs
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
6.625% Notes due 2019
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
350,000
|
|
|
$
|
4,591
|
|
|
$
|
345,409
|
|
6.50% Notes due 2021
|
350,000
|
|
|
4,106
|
|
|
345,894
|
|
|
350,000
|
|
|
4,806
|
|
|
345,194
|
|
||||||
6.125% Notes due 2022
|
600,000
|
|
|
8,714
|
|
|
591,286
|
|
|
600,000
|
|
|
9,812
|
|
|
590,188
|
|
||||||
6.50% Notes due 2023
|
400,000
|
|
|
5,231
|
|
|
394,769
|
|
|
400,000
|
|
|
5,969
|
|
|
394,031
|
|
||||||
5.0% Notes due 2024
|
500,000
|
|
|
7,455
|
|
|
492,545
|
|
|
500,000
|
|
|
8,377
|
|
|
491,623
|
|
||||||
5.625% Notes due 2025
|
500,000
|
|
|
8,524
|
|
|
491,476
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total
|
$
|
2,350,000
|
|
|
$
|
34,030
|
|
|
$
|
2,315,970
|
|
|
$
|
2,200,000
|
|
|
$
|
33,555
|
|
|
$
|
2,166,445
|
|
(1)
|
Prior period amounts have been reclassified to conform to the current period presentation on the accompanying balance sheets. Please refer to the section
Recently Issued Accounting Standards
in
Note 1 – Summary of Significant Accounting Policies
for additional discussion.
|
Years Ending December 31,
|
|
Amount
(1)
(in thousands)
|
||
2016
|
|
$
|
132,747
|
|
2017
|
|
128,074
|
|
|
2018
|
|
131,489
|
|
|
2019
|
|
142,161
|
|
|
2020
|
|
141,854
|
|
|
Thereafter
|
|
288,113
|
|
|
Total
|
|
$
|
964,438
|
|
(1)
|
During the third quarter of 2015, the Company vacated its office space in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive
$3.5 million
of sublease income as follows:
$831,000
in
2016
,
$953,000
in
2017
,
$978,000
in
2018
, and
$741,000
in
2019
.
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||
|
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)
|
433,660
|
|
|
$
|
73.63
|
|
|
572,469
|
|
|
$
|
66.07
|
|
|
669,308
|
|
|
$
|
63.91
|
|
Granted
(1)
|
320,753
|
|
|
$
|
45.34
|
|
|
202,404
|
|
|
$
|
94.66
|
|
|
274,831
|
|
|
$
|
64.13
|
|
Vested
(1)
|
(76,438
|
)
|
|
$
|
51.76
|
|
|
(206,830
|
)
|
|
$
|
64.79
|
|
|
(345,005
|
)
|
|
$
|
60.06
|
|
Forfeited
(1)
|
(51,647
|
)
|
|
$
|
73.62
|
|
|
(134,383
|
)
|
|
$
|
86.72
|
|
|
(26,665
|
)
|
|
$
|
69.74
|
|
Non-vested at end of year
(1)
|
626,328
|
|
|
$
|
61.81
|
|
|
433,660
|
|
|
$
|
73.63
|
|
|
572,469
|
|
|
$
|
66.07
|
|
(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,
|
|||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||
|
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
|
515,724
|
|
|
$
|
68.29
|
|
|
580,431
|
|
|
$
|
57.05
|
|
|
496,244
|
|
|
$
|
51.81
|
|
Granted
|
356,246
|
|
|
$
|
43.72
|
|
|
234,560
|
|
|
$
|
83.98
|
|
|
329,939
|
|
|
$
|
60.01
|
|
Vested
|
(278,289
|
)
|
|
$
|
63.12
|
|
|
(253,031
|
)
|
|
$
|
58.19
|
|
|
(207,376
|
)
|
|
$
|
49.73
|
|
Forfeited
|
(49,944
|
)
|
|
$
|
66.53
|
|
|
(46,236
|
)
|
|
$
|
62.06
|
|
|
(38,376
|
)
|
|
$
|
54.37
|
|
Non-vested at end of year
|
543,737
|
|
|
$
|
55.01
|
|
|
515,724
|
|
|
$
|
68.29
|
|
|
580,431
|
|
|
$
|
57.05
|
|
|
|
|
Weighted -
|
|
|
|||||
|
|
|
Average
|
|
Aggregate
|
|||||
|
|
|
Exercise
|
|
Intrinsic
|
|||||
|
Shares
|
|
Price
|
|
Value
|
|||||
For the year ended December 31, 2013
|
|
|
|
|
|
|||||
Outstanding, start of year
|
267,846
|
|
|
$
|
14.95
|
|
|
|
||
Exercised
|
(228,758
|
)
|
|
$
|
13.92
|
|
|
$
|
12,326,994
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
|
||
Outstanding, end of year
|
39,088
|
|
|
$
|
20.87
|
|
|
$
|
2,432,837
|
|
Vested and exercisable at end of year
|
39,088
|
|
|
$
|
20.87
|
|
|
$
|
2,432,837
|
|
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,
|
|||||||
|
2015
|
|
2014
|
|
2013
|
|||
Risk free interest rate
|
0.1
|
%
|
|
0.1
|
%
|
|
0.1
|
%
|
Dividend yield
|
0.2
|
%
|
|
0.1
|
%
|
|
0.2
|
%
|
Volatility factor of the expected market
price of the Company’s common stock
|
61.2
|
%
|
|
33.0
|
%
|
|
41.1
|
%
|
Expected life (in years)
|
0.5
|
|
|
0.5
|
|
|
0.5
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
General and administrative expense
|
$
|
3,239
|
|
|
$
|
8,326
|
|
|
$
|
13,734
|
|
Exploration expense
|
259
|
|
|
690
|
|
|
1,310
|
|
|||
Total
|
$
|
3,498
|
|
|
$
|
9,016
|
|
|
$
|
15,044
|
|
|
For the Years Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Change in benefit obligation:
|
|
|
|
||||
Projected benefit obligation at beginning of year
|
$
|
57,867
|
|
|
$
|
43,285
|
|
Service cost
|
7,949
|
|
|
6,335
|
|
||
Interest cost
|
2,496
|
|
|
2,191
|
|
||
Actuarial loss
|
2,397
|
|
|
8,821
|
|
||
Benefits paid
|
(8,162
|
)
|
|
(2,765
|
)
|
||
Projected benefit obligation at end of year
|
62,547
|
|
|
57,867
|
|
||
|
|
|
|
||||
Change in plan assets:
|
|
|
|
||||
Fair value of plan assets at beginning of year
|
27,940
|
|
|
24,658
|
|
||
Actual return on plan assets
|
(410
|
)
|
|
737
|
|
||
Employer contribution
|
6,401
|
|
|
5,310
|
|
||
Benefits paid
|
(8,162
|
)
|
|
(2,765
|
)
|
||
Fair value of plan assets at end of year
|
25,769
|
|
|
27,940
|
|
||
Funded status at end of year
|
$
|
(36,778
|
)
|
|
$
|
(29,927
|
)
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Projected benefit obligation
|
$
|
62,547
|
|
|
$
|
57,867
|
|
|
|
|
|
||||
Accumulated benefit obligation
|
$
|
46,439
|
|
|
$
|
43,205
|
|
Less: Fair value of plan assets
|
(25,769
|
)
|
|
(27,940
|
)
|
||
Underfunded accumulated benefit obligation
|
$
|
20,670
|
|
|
$
|
15,265
|
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Unrecognized actuarial losses
|
$
|
20,966
|
|
|
$
|
17,812
|
|
Unrecognized prior service costs
|
101
|
|
|
118
|
|
||
Unrecognized transition obligation
|
—
|
|
|
—
|
|
||
Accumulated other comprehensive loss
|
$
|
21,067
|
|
|
$
|
17,930
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Net actuarial gain (loss)
|
$
|
(4,990
|
)
|
|
$
|
(10,062
|
)
|
|
$
|
2,766
|
|
Prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|||
Less:
|
|
|
|
|
|
||||||
Amortization of prior service cost
|
(17
|
)
|
|
(17
|
)
|
|
(17
|
)
|
|||
Amortization of net actuarial loss
|
(1,486
|
)
|
|
(689
|
)
|
|
(1,222
|
)
|
|||
Settlements
|
(350
|
)
|
|
—
|
|
|
—
|
|
|||
Total other comprehensive income (loss)
|
$
|
(3,137
|
)
|
|
$
|
(9,356
|
)
|
|
$
|
4,005
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
||||||
Service cost
|
$
|
7,949
|
|
|
$
|
6,335
|
|
|
$
|
6,291
|
|
Interest cost
|
2,496
|
|
|
2,191
|
|
|
1,627
|
|
|||
Expected return on plan assets that reduces periodic pension cost
|
(2,182
|
)
|
|
(1,978
|
)
|
|
(1,538
|
)
|
|||
Amortization of prior service cost
|
17
|
|
|
17
|
|
|
17
|
|
|||
Amortization of net actuarial loss
|
1,486
|
|
|
689
|
|
|
1,222
|
|
|||
Settlements
|
350
|
|
|
—
|
|
|
—
|
|
|||
Net periodic benefit cost
|
$
|
10,116
|
|
|
$
|
7,254
|
|
|
$
|
7,619
|
|
|
As of December 31,
|
||||
|
2015
|
|
2014
|
|
2013
|
Projected benefit obligation
|
|
|
|
|
|
Discount rate
|
4.7%
|
|
4.3%
|
|
5.0%
|
Rate of compensation increase
|
6.2%
|
|
6.2%
|
|
6.2%
|
Net periodic benefit cost
|
|
|
|
|
|
Discount rate
|
4.3%
|
|
5.0%
|
|
3.9%
|
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
|
|
2016
|
|
2015
|
|
2014
|
|||
Equity securities
|
|
42.0
|
%
|
|
39.1
|
%
|
|
39.6
|
%
|
Fixed income securities
|
|
35.0
|
%
|
|
34.0
|
%
|
|
33.9
|
%
|
Other securities
|
|
23.0
|
%
|
|
26.9
|
%
|
|
26.5
|
%
|
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, 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
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
As of December 31, 2014
|
|
|
|
|
|
|
|
|
|
|||||||||
Cash
|
—
|
%
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity Securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Domestic
(1)
|
27.1
|
%
|
|
7,569
|
|
|
5,550
|
|
|
2,019
|
|
|
—
|
|
||||
International
(2)
|
12.5
|
%
|
|
3,498
|
|
|
3,498
|
|
|
—
|
|
|
—
|
|
||||
Total Equity Securities
|
39.6
|
%
|
|
11,067
|
|
|
9,048
|
|
|
2,019
|
|
|
—
|
|
||||
Fixed Income Securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
High-Yield Bonds
(3)
|
2.9
|
%
|
|
797
|
|
|
797
|
|
|
—
|
|
|
—
|
|
||||
Core Fixed Income
(4)
|
22.4
|
%
|
|
6,247
|
|
|
6,247
|
|
|
—
|
|
|
—
|
|
||||
Floating Rate Corp Loans
(5)
|
8.6
|
%
|
|
2,413
|
|
|
2,413
|
|
|
—
|
|
|
—
|
|
||||
Total Fixed Income Securities
|
33.9
|
%
|
|
9,457
|
|
|
9,457
|
|
|
—
|
|
|
—
|
|
||||
Other Securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Commodities
(6)
|
2.9
|
%
|
|
810
|
|
|
810
|
|
|
—
|
|
|
—
|
|
||||
Real Estate
(7)
|
4.7
|
%
|
|
1,327
|
|
|
—
|
|
|
—
|
|
|
1,327
|
|
||||
Collective Investment Trusts
(8)
|
4.1
|
%
|
|
1,149
|
|
|
—
|
|
|
1,149
|
|
|
—
|
|
||||
Hedge Fund
(9)
|
14.8
|
%
|
|
4,130
|
|
|
593
|
|
|
—
|
|
|
3,537
|
|
||||
Total Other Securities
|
26.5
|
%
|
|
7,416
|
|
|
1,403
|
|
|
1,149
|
|
|
4,864
|
|
||||
Total Investments
|
100.0
|
%
|
|
$
|
27,940
|
|
|
$
|
19,908
|
|
|
$
|
3,168
|
|
|
$
|
4,864
|
|
(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 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, 2014
|
$
|
3,421
|
|
Purchases
|
1,232
|
|
|
Realized gain on assets
|
144
|
|
|
Unrealized gain on assets
|
67
|
|
|
Balance at December 31, 2014
|
$
|
4,864
|
|
Purchases
|
—
|
|
|
Realized gain on assets
|
165
|
|
|
Unrealized gain on assets
|
16
|
|
|
Balance at December 31, 2015
|
$
|
5,045
|
|
Years Ending December 31,
|
|
(in thousands)
|
||
2016
|
|
$
|
3,618
|
|
2017
|
|
$
|
4,350
|
|
2018
|
|
$
|
4,605
|
|
2019
|
|
$
|
6,057
|
|
2020
|
|
$
|
6,846
|
|
2021 through 2025
|
|
$
|
47,188
|
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Beginning asset retirement obligation
|
$
|
122,124
|
|
|
$
|
121,186
|
|
Liabilities incurred
|
14,471
|
|
|
13,506
|
|
||
Liabilities settled
|
(24,781
|
)
|
|
(11,372
|
)
|
||
Accretion expense
|
5,091
|
|
|
6,090
|
|
||
Revision to estimated cash flows
|
23,969
|
|
|
(7,286
|
)
|
||
Ending asset retirement obligation
|
$
|
140,874
|
|
|
$
|
122,124
|
|
Contract Period
|
|
NYMEX WTI Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(Bbls)
|
|
(per Bbl)
|
|||
First quarter 2016
|
|
1,868,000
|
|
|
$
|
86.93
|
|
Second quarter 2016
|
|
1,752,000
|
|
|
$
|
86.73
|
|
Third quarter 2016
|
|
1,170,000
|
|
|
$
|
90.29
|
|
Fourth quarter 2016
|
|
780,000
|
|
|
$
|
90.05
|
|
All oil swaps
|
|
5,570,000
|
|
|
|
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(MMBtu)
|
|
(per MMBtu)
|
|||
First quarter 2016
|
|
23,341,000
|
|
|
$
|
3.82
|
|
Second quarter 2016
|
|
20,780,000
|
|
|
$
|
3.40
|
|
Third quarter 2016
|
|
18,829,000
|
|
|
$
|
3.38
|
|
Fourth quarter 2016
|
|
17,236,000
|
|
|
$
|
3.82
|
|
2017
|
|
37,528,000
|
|
|
$
|
4.09
|
|
2018
|
|
30,606,000
|
|
|
$
|
4.27
|
|
2019
|
|
24,415,000
|
|
|
$
|
4.34
|
|
All gas swaps*
|
|
172,735,000
|
|
|
|
|
|
OPIS Purity Ethane Mont Belvieu
|
|
OPIS Propane Mont Belvieu Non-TET
|
|
OPIS Normal Butane Mont Belvieu Non-TET
|
|
OPIS Isobutane 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 |
||||||||||||
|
|
(Bbls)
|
(per Bbl)
|
|
(Bbls)
|
(per Bbl)
|
|
(Bbls)
|
(per Bbl)
|
|
(Bbls)
|
(per Bbl)
|
||||||||||||
First quarter 2016
|
|
926,000
|
|
$
|
8.29
|
|
|
1,059,000
|
|
$
|
19.60
|
|
|
143,000
|
|
$
|
25.62
|
|
|
122,000
|
|
$
|
25.87
|
|
Second quarter 2016
|
|
828,000
|
|
$
|
8.28
|
|
|
949,000
|
|
$
|
19.64
|
|
|
130,000
|
|
$
|
25.62
|
|
|
111,000
|
|
$
|
25.87
|
|
Third quarter 2016
|
|
751,000
|
|
$
|
8.70
|
|
|
862,000
|
|
$
|
19.03
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
Fourth quarter 2016
|
|
688,000
|
|
$
|
8.71
|
|
|
791,000
|
|
$
|
18.53
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
2017
|
|
2,271,000
|
|
$
|
9.16
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
2018
|
|
1,671,000
|
|
$
|
10.65
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
2019
|
|
1,200,000
|
|
$
|
10.92
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
2020
|
|
539,000
|
|
$
|
11.13
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
|
—
|
|
$
|
—
|
|
Total NGL swaps
|
|
8,874,000
|
|
|
|
3,661,000
|
|
|
|
273,000
|
|
|
|
233,000
|
|
|
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Purchased Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Total Volumes
|
|||||||
|
|
(MMBtu)
|
|
(per MMBtu)
|
|
(MMBtu)
|
|
(per MMBtu)
|
|
(MMBtu)
|
|||||||
First quarter 2016
|
|
23,341,000
|
|
|
$
|
3.82
|
|
|
—
|
|
|
$
|
—
|
|
|
23,341,000
|
|
Second quarter 2016
|
|
20,780,000
|
|
|
$
|
3.40
|
|
|
—
|
|
|
$
|
—
|
|
|
20,780,000
|
|
Third quarter 2016
|
|
18,829,000
|
|
|
$
|
3.38
|
|
|
—
|
|
|
$
|
—
|
|
|
18,829,000
|
|
Fourth quarter 2016
|
|
17,236,000
|
|
|
$
|
3.82
|
|
|
—
|
|
|
$
|
—
|
|
|
17,236,000
|
|
2017
|
|
76,135,000
|
|
|
$
|
4.26
|
|
|
—
|
|
|
$
|
—
|
|
|
76,135,000
|
|
2018
|
|
30,606,000
|
|
|
$
|
4.27
|
|
|
(30,606,000
|
)
|
|
$
|
4.27
|
|
|
—
|
|
2019
|
|
24,415,000
|
|
|
$
|
4.34
|
|
|
(24,415,000
|
)
|
|
$
|
4.34
|
|
|
—
|
|
All gas swaps*
|
|
211,342,000
|
|
|
|
|
(55,021,000
|
)
|
|
|
|
156,321,000
|
|
|
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
|
|
|
As of December 31, 2014
|
||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
||||
|
(in thousands)
|
||||||||||
Commodity Contracts
|
Current assets
|
|
$
|
402,668
|
|
|
Current liabilities
|
|
$
|
—
|
|
Commodity Contracts
|
Noncurrent assets
|
|
189,540
|
|
|
Noncurrent liabilities
|
|
70
|
|
||
Derivatives not designated as hedging instruments
|
|
|
$
|
592,208
|
|
|
|
|
$
|
70
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||
|
|
As of December 31,
|
|
As of December 31,
|
||||||||||||
Offsetting of Derivative Assets and Liabilities
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
|
|
(in thousands)
|
||||||||||||||
Gross amounts presented in the accompanying balance sheets
|
|
$
|
488,411
|
|
|
$
|
592,208
|
|
|
$
|
(8
|
)
|
|
$
|
(70
|
)
|
Amounts not offset in the accompanying balance sheets
|
|
(8
|
)
|
|
(70
|
)
|
|
8
|
|
|
70
|
|
||||
Net amounts
|
|
$
|
488,403
|
|
|
$
|
592,138
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Derivative settlement (gain) loss:
|
|
|
|
|
|
||||||
Oil contracts
|
$
|
(362,219
|
)
|
|
$
|
(28,410
|
)
|
|
$
|
15,161
|
|
Gas contracts
(1)
|
(123,180
|
)
|
|
26,706
|
|
|
(30,338
|
)
|
|||
NGL contracts
|
(27,167
|
)
|
|
(10,911
|
)
|
|
(6,885
|
)
|
|||
Total derivative settlement gain
|
$
|
(512,566
|
)
|
|
$
|
(12,615
|
)
|
|
$
|
(22,062
|
)
|
|
|
|
|
|
|
||||||
Total derivative (gain) loss:
|
|
|
|
|
|
||||||
Oil contracts
|
$
|
(191,165
|
)
|
|
$
|
(457,082
|
)
|
|
$
|
14,665
|
|
Gas contracts
|
(189,734
|
)
|
|
(93,267
|
)
|
|
(14,053
|
)
|
|||
NGL contracts
|
(27,932
|
)
|
|
(32,915
|
)
|
|
(3,692
|
)
|
|||
Total derivative gain
|
$
|
(408,831
|
)
|
|
$
|
(583,264
|
)
|
|
$
|
(3,080
|
)
|
(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.
|
|
|
|
Location on
Accompanying
Statements of
Operations
|
|
For the Years Ended December 31,
|
||||||||||
|
Derivatives
|
|
|
2015
|
|
2014
|
|
2013
|
|||||||
|
|
|
|
|
(in thousands)
|
||||||||||
Amount reclassified from
AOCL
|
Commodity Contracts
|
|
Other operating revenues
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,115
|
|
•
|
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)
|
$
|
—
|
|
|
$
|
488,411
|
|
|
$
|
—
|
|
Proved oil and gas properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
124,184
|
|
Other property and equipment
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
629
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
—
|
|
Net Profits Plan
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,611
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
592,208
|
|
|
$
|
—
|
|
Proved oil and gas properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
33,423
|
|
Oil and gas properties held for sale
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
17,891
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
70
|
|
|
$
|
—
|
|
Net Profits Plan
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
27,136
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
27,136
|
|
|
$
|
56,985
|
|
|
$
|
78,827
|
|
Net increase (decrease) in liability
(1)
|
(12,238
|
)
|
|
(12,492
|
)
|
|
3,527
|
|
|||
Net settlements
(1) (2)
|
(7,287
|
)
|
|
(17,357
|
)
|
|
(25,369
|
)
|
|||
Transfers in (out) of Level 3
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance
|
$
|
7,611
|
|
|
$
|
27,136
|
|
|
$
|
56,985
|
|
(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. The amounts in the table include cash payments made or accrued under the Net Profits Plan of
$3.8 million
,
$8.3 million
, and
$10.3 million
for the years ended
December 31, 2015
,
2014
, and
2013
, respectively, as a result of the divestitures of properties subject to the Net Profits Plan.
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
2019 Notes
(1)
|
$
|
—
|
|
|
$
|
350,018
|
|
2021 Notes
|
$
|
262,938
|
|
|
$
|
343,000
|
|
2022 Notes
|
$
|
440,250
|
|
|
$
|
556,500
|
|
2023 Notes
|
$
|
296,000
|
|
|
$
|
379,000
|
|
2024 Notes
|
$
|
334,065
|
|
|
$
|
435,000
|
|
2025 Notes
(1)
|
$
|
326,875
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance on January 1,
|
$
|
43,589
|
|
|
$
|
34,527
|
|
|
$
|
9,100
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
11,952
|
|
|
43,589
|
|
|
34,527
|
|
|||
Divestitures
|
(809
|
)
|
|
—
|
|
|
—
|
|
|||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
|
(18,485
|
)
|
|
(33,340
|
)
|
|
(9,100
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
(24,295
|
)
|
|
(1,187
|
)
|
|
—
|
|
|||
Ending balance at December 31,
|
$
|
11,952
|
|
|
$
|
43,589
|
|
|
$
|
34,527
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Development costs
(1)
|
$
|
1,234,114
|
|
|
$
|
1,782,324
|
|
|
$
|
1,350,116
|
|
Exploration costs
|
132,465
|
|
|
288,270
|
|
|
168,612
|
|
|||
Acquisitions
|
|
|
|
|
|
||||||
Proved properties
|
10,040
|
|
|
272,902
|
|
|
29,859
|
|
|||
Unproved properties
(2)
|
18,382
|
|
|
368,208
|
|
|
172,546
|
|
|||
Total, including asset retirement obligation
(3)(4)
|
$
|
1,395,001
|
|
|
$
|
2,711,704
|
|
|
$
|
1,721,133
|
|
(1)
|
Includes facility costs of
$75.6 million
,
$75.1 million
, and
$49.5 million
for the years ended
December 31, 2015
,
2014
, and
2013
, respectively.
|
(2)
|
Includes
$924,000
,
$288.7 million
, and
$58.5 million
of unproved properties acquired as part of proved property acquisitions for the years ended
December 31, 2015
,
2014
, and
2013
, respectively. The remaining balance relates to leasing activity.
|
(3)
|
Includes capitalized interest of
$25.1 million
,
$16.2 million
, and
$11.0 million
for the years ended
December 31, 2015
,
2014
, and
2013
, respectively.
|
(4)
|
Includes amounts relating to estimated asset retirement obligations of
$38.5 million
,
$11.4 million
, and
$26.8 million
for the years ended
December 31, 2015
,
2014
, and
2013
, respectively.
|
|
||||||||||||||||||||||||||
|
For the Years Ended December 31,
|
|||||||||||||||||||||||||
|
2015
(1)
|
|
2014
(2)
|
|
2013
(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
|
169.7
|
|
|
1,466.5
|
|
|
133.5
|
|
|
126.6
|
|
|
1,189.3
|
|
|
103.9
|
|
|
92.2
|
|
|
833.4
|
|
|
62.3
|
|
Revisions of previous estimate
|
(46.2
|
)
|
|
(369.6
|
)
|
|
(40.6
|
)
|
|
(5.1
|
)
|
|
46.0
|
|
|
7.8
|
|
|
(5.2
|
)
|
|
68.8
|
|
|
(1.3
|
)
|
Discoveries and extensions
|
16.9
|
|
|
122.3
|
|
|
9.3
|
|
|
15.0
|
|
|
103.5
|
|
|
10.5
|
|
|
34.6
|
|
|
399.2
|
|
|
39.8
|
|
Infill reserves in an existing proved field
|
24.9
|
|
|
356.2
|
|
|
29.7
|
|
|
32.0
|
|
|
270.8
|
|
|
24.1
|
|
|
21.6
|
|
|
118.7
|
|
|
13.2
|
|
Sales of
reserves
(4)
|
(1.9
|
)
|
|
(138.4
|
)
|
|
(0.4
|
)
|
|
(1.9
|
)
|
|
(1.1
|
)
|
|
—
|
|
|
(3.4
|
)
|
|
(85.1
|
)
|
|
(0.6
|
)
|
Purchases of minerals in place
|
1.1
|
|
|
0.6
|
|
|
—
|
|
|
19.8
|
|
|
10.9
|
|
|
0.2
|
|
|
0.7
|
|
|
3.6
|
|
|
—
|
|
Production
|
(19.2
|
)
|
|
(173.6
|
)
|
|
(16.1
|
)
|
|
(16.7
|
)
|
|
(152.9
|
)
|
|
(13.0
|
)
|
|
(13.9
|
)
|
|
(149.3
|
)
|
|
(9.5
|
)
|
End of year
|
145.3
|
|
|
1,264.0
|
|
|
115.4
|
|
|
169.7
|
|
|
1,466.5
|
|
|
133.5
|
|
|
126.6
|
|
|
1,189.3
|
|
|
103.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Beginning of year
|
89.3
|
|
|
784.6
|
|
|
66.7
|
|
|
70.2
|
|
|
569.2
|
|
|
43.8
|
|
|
58.8
|
|
|
483.2
|
|
|
27.2
|
|
End of year
|
75.6
|
|
|
644.4
|
|
|
61.5
|
|
|
89.3
|
|
784.6
|
|
|
66.7
|
|
|
70.2
|
|
|
569.2
|
|
|
43.8
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Beginning of year
|
80.4
|
|
|
682.0
|
|
|
66.8
|
|
|
56.3
|
|
|
620.1
|
|
|
60.2
|
|
|
33.5
|
|
|
350.2
|
|
|
35.1
|
|
End of year
|
69.6
|
|
|
619.7
|
|
|
53.9
|
|
|
80.4
|
|
|
682.0
|
|
|
66.8
|
|
|
56.3
|
|
|
620.1
|
|
|
60.2
|
|
(1)
|
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 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 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.
|
(2)
|
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 assets.
|
(3)
|
For the year ended December 31, 2013, the Company added
195.5
MMBOE from its drilling program and had upward engineering revisions of
5.0
MMBOE related primarily to an upward performance revision of
4.4
MMBOE.
|
(4)
|
Please refer to
Note 3 – Divestitures, Assets Held for Sale, and Acquisitions
for additional information on assets divested.
|
|
As of December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Future cash inflows
|
$
|
11,337,865
|
|
|
$
|
25,897,730
|
|
|
$
|
19,895,360
|
|
Future production costs
|
(6,234,687
|
)
|
|
(9,986,239
|
)
|
|
(7,771,747
|
)
|
|||
Future development costs
|
(2,005,599
|
)
|
|
(3,294,164
|
)
|
|
(2,891,325
|
)
|
|||
Future income taxes
|
—
|
|
|
(3,511,352
|
)
|
|
(2,722,230
|
)
|
|||
Future net cash flows
|
3,097,579
|
|
|
9,105,975
|
|
|
6,510,058
|
|
|||
10 percent annual discount
|
(1,228,671
|
)
|
|
(3,407,192
|
)
|
|
(2,500,619
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
1,868,908
|
|
|
$
|
5,698,783
|
|
|
$
|
4,009,439
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Standardized measure, beginning of year
|
$
|
5,698,783
|
|
|
$
|
4,009,439
|
|
|
$
|
3,021,014
|
|
Sales of oil, gas, and NGLs produced, net of production costs
|
(776,272
|
)
|
|
(1,765,666
|
)
|
|
(1,602,505
|
)
|
|||
Net changes in prices and production costs
|
(4,709,908
|
)
|
|
(75,966
|
)
|
|
142,199
|
|
|||
Extensions, discoveries and other including infill reserves in an existing proved field, net of related costs
|
386,069
|
|
|
1,819,657
|
|
|
2,309,075
|
|
|||
Sales of reserves in place
|
(262,210
|
)
|
|
(49,736
|
)
|
|
(259,031
|
)
|
|||
Purchase of reserves in place
|
4,686
|
|
|
413,175
|
|
|
30,771
|
|
|||
Previously estimated development costs incurred during the period
|
449,738
|
|
|
1,015,694
|
|
|
581,107
|
|
|||
Changes in estimated future development costs
|
191,447
|
|
|
138,247
|
|
|
68,613
|
|
|||
Revisions of previous quantity estimates
|
(1,819,639
|
)
|
|
167,500
|
|
|
82,226
|
|
|||
Accretion of discount
|
761,746
|
|
|
552,852
|
|
|
384,914
|
|
|||
Net change in income taxes
|
1,863,868
|
|
|
(399,587
|
)
|
|
(690,953
|
)
|
|||
Changes in timing and other
|
80,600
|
|
|
(126,826
|
)
|
|
(57,991
|
)
|
|||
Standardized measure, end of year
|
$
|
1,868,908
|
|
|
$
|
5,698,783
|
|
|
$
|
4,009,439
|
|
|
First
|
|
Second
(2)
|
|
Third
(3)
|
|
Fourth
(3) (4)
|
||||||||
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
||||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
||||||||
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
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
||||||||
Total operating revenues and other income
|
$
|
632,720
|
|
|
$
|
674,980
|
|
|
$
|
618,786
|
|
|
$
|
595,821
|
|
Total operating expenses
|
504,086
|
|
|
553,264
|
|
|
261,807
|
|
|
37,336
|
|
||||
Income from operations
|
$
|
128,634
|
|
|
$
|
121,716
|
|
|
$
|
356,979
|
|
|
$
|
558,485
|
|
Income before income taxes
|
$
|
104,470
|
|
|
$
|
95,829
|
|
|
$
|
333,686
|
|
|
$
|
530,714
|
|
Net income
|
$
|
65,607
|
|
|
$
|
59,780
|
|
|
$
|
208,938
|
|
|
$
|
331,726
|
|
Basic net income per common share
(1)
|
$
|
0.98
|
|
|
$
|
0.89
|
|
|
$
|
3.10
|
|
|
$
|
4.92
|
|
Diluted net income per common share
(1)
|
$
|
0.96
|
|
|
$
|
0.88
|
|
|
$
|
3.05
|
|
|
$
|
4.91
|
|
Dividends declared per common share
|
$
|
0.05
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
(1)
|
Amounts may not sum due to rounding.
|
(2)
|
During the second quarter of 2015, the Company recorded a
$71.9 million
net gain on divestiture activity resulting from the sale of its Mid-Continent assets offset by write-downs on certain other assets held for sale. Please refer to
Note 3 – Divestitures, Assets Held for Sale, and Acquisitions
in Part II, Item 8 of this report for additional information.
Additionally, the Company recorded a
$16.6 million
net loss on the early extinguishment of its 2019 Notes. Please refer to
Note 5 - Long-Term Debt
in Part II, Item 8 of this report for additional information.
|
(3)
|
The volatility of commodity prices at the end of 2014 and throughout 2015 has resulted in significant net derivative gains recorded for the years ended December 31, 2015, and 2014, with the third quarter of 2015 including a
$212.3 million
net derivative gain and the third and fourth quarters of 2014 including a
$190.7 million
and
$616.7 million
net derivative gain, respectively. Please refer to the caption
Derivative gain
included in
Comparison of Financial Results and Trends between
2015
and
2014
and
between
2014
and
2013
included in Part II, Item 7 of this report for additional discussion.
|
(4)
|
During the fourth quarter of 2015, the Company recorded
$344.2 million
of impairment of proved properties expense,
$54.6 million
of abandonment and impairment of unproved properties expense, and
$49.4 million
of impairment of other property and equipment expense. During the fourth quarter of 2014, the Company recorded
$84.5 million
of impairment of proved properties expense and
$57.2 million
of abandonment and impairment of unproved properties expense. Please refer to the caption
Impairment of Proved and Unproved Properties
included in
Note 1 - Summary of Significant Accounting Policies
for additional discussion.
|
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.
|
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, and 2013 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The awards granted in
2015
,
2014
, and
2013
under the Equity Plan were
714,949
,
464,641
, and
632,939
, 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 Internal Revenue Code. Shares issued under the ESPP totaled
197,214
,
83,136
, and
77,427
in
2015
,
2014
, and
2013
, 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
$55.01
and $63.43, 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)
|
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)
|
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 Bylaws of SM Energy Company, effective as of December 15, 2015 (filed as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on December 21, 2015, and incorporated herein by reference)
|
4.1
|
Indenture related to the 6.625% Senior Notes due 2019, dated as of 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 as of 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)
|
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†
|
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)
|
10.21†
|
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)
|
10.22†
|
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)
|
10.23*†
|
Summary of Compensation Arrangements for Non-Employee Directors
|
10.24
|
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)
|
10.25
|
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)
|
10.26
|
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)
|
10.27
|
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)
|
10.28
|
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)
|
10.29*†
|
Amendment No. 3 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2016
|
10.30
***
|
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)
|
10.31
|
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)
|
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 24, 2016
|
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 24, 2016
|
Javan D. Ottoson
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ A. WADE PURSELL
|
|
Executive Vice President and Chief Financial Officer
|
|
February 24, 2016
|
A. Wade Pursell
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ MARK T. SOLOMON
|
|
Vice President - Controller and Assistant Secretary
|
|
February 24, 2016
|
Mark T. Solomon
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ WILLIAM D. SULLIVAN
|
|
Chairman of the Board of Directors
|
|
February 24, 2016
|
William D. Sullivan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ LARRY W. BICKLE
|
|
Director
|
|
February 24, 2016
|
Larry W. Bickle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ STEPHEN R. BRAND
|
|
Director
|
|
February 24, 2016
|
Stephen R. Brand
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ WILLIAM J. GARDINER
|
|
Director
|
|
February 24, 2016
|
William J. Gardiner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ LOREN M. LEIKER
|
|
Director
|
|
February 24, 2016
|
Loren
M. Leiker
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ RAMIRO G. PERU
|
|
Director
|
|
February 24, 2016
|
Ramiro G. Peru
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ JULIO M. QUINTANA
|
|
Director
|
|
February 24, 2016
|
Julio M. Quintana
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ ROSE M. ROBESON
|
|
Director
|
|
February 24, 2016
|
Rose M. Robeson
|
|
|
|
|
|
|
|
|
|
•
|
Audit Committee - $20,000
|
•
|
Compensation Committee - $15,000
|
•
|
Nominating and Corporate Governance Committee - $10,000
|
1)
|
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 3,308 shares of SM Energy common stock issued on May 20, 2015, under SM Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year board service period and carry a subsequent six month transfer restriction imposed by SM Energy.
|
2)
|
A retainer for the Non-Executive Chairman of the Board valued at $85,000. This resulted in a grant of 1,562 shares of SM Energy common stock issued on May 20, 2015, under SM Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year board service period and carry a subsequent six month transfer restriction imposed by SM Energy.
|
3)
|
Steven R. Brand, William J. Gardiner, Loren M. Leiker, Julio M. Quintana, Rose M. Robeson and William D. Sullivan each elected to receive SM Energy common stock for
|
(a)
|
Each Employee who was an Active Participant immediately prior to the Effective Date and is a Covered Employee on the Effective Date will continue to be an Active Participant as of the Effective Date.
|
(a)
|
Each other Employee will become an Active Participant on the first day of the calendar month coincident with or next following the date on which such Employee attains Age 21 and completes one Year of Eligibility Service, if then a Covered Employee.
|
(b)
|
A Participant (or a former Participant) who has a Separation from Service and who is later reemployed as a Covered Employee will become an Active Participant as of the date on which he or she first again completes an Hour of Service as a Covered Employee, but, if he or she has had a Break in Service, only if he or she (1) had any vested interest in his or her Accrued Benefit as of the prior Separation from Service or (2) again completes one Hour of Service at a time when the consecutive Breaks in Service do not equal or exceed the greater of five, or the number of Years of Eligibility Service credit prior to the Break in Service.
|
(c)
|
If an individual is not a Covered Employee on the date on which the individual would otherwise become an Active Participant (but for the fact that such individual is not then a Covered Employee), such individual will become an Active Participant as of the first date thereafter on which the individual becomes a Covered Employee; but, if there was a Break in Service, only if the individual (1) had any vested interest in his or her Accrued Benefit as of the prior Separation from Service or (2) again completes one Hour of Service at a time when his or her consecutive Breaks in Service do not equal or exceed the greater of five, or the number of Years of Eligibility Service prior to the Break in Service.
|
(d)
|
Notwithstanding the above, effective January 1, 2016, the Plan is frozen with respect to participation. Accordingly, Employees hired on and after January 1, 2015 will not be eligible to participate in the Plan.
|
|
Year Ended December 31,
|
||||||||||||||
|
2015
|
2014
|
2013
|
2012
|
2011
|
||||||||||
|
(in thousands, except ratios)
|
||||||||||||||
|
|
|
|
|
|
||||||||||
Pretax income (loss) from continuing operations
|
$
|
(722,861
|
)
|
$
|
1,064,699
|
|
$
|
278,611
|
|
$
|
(83,517
|
)
|
$
|
339,001
|
|
|
|
|
|
|
|
||||||||||
Add: Fixed charges
|
155,510
|
|
117,147
|
|
102,758
|
|
77,841
|
|
58,030
|
|
|||||
Add: Amortization of capitalized interest
|
9,116
|
|
11,448
|
|
11,784
|
|
9,095
|
|
5,107
|
|
|||||
Less: Capitalized interest
|
(25,051
|
)
|
(16,165
|
)
|
(10,952
|
)
|
(12,135
|
)
|
(10,785
|
)
|
|||||
Earnings before fixed charges
|
$
|
(583,286
|
)
|
$
|
1,177,129
|
|
$
|
382,201
|
|
$
|
(8,716
|
)
|
$
|
391,353
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
||||||||||
Interest expense
(1)
|
$
|
128,149
|
|
$
|
98,554
|
|
$
|
89,711
|
|
$
|
63,720
|
|
$
|
45,849
|
|
Capitalized interest
|
25,051
|
|
16,165
|
|
10,952
|
|
12,135
|
|
10,785
|
|
|||||
Interest expense component of rent
(2)
|
2,310
|
|
2,428
|
|
2,095
|
|
1,986
|
|
1,396
|
|
|||||
Total fixed charges
|
$
|
155,510
|
|
$
|
117,147
|
|
$
|
102,758
|
|
$
|
77,841
|
|
$
|
58,030
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
—
|
|
10.0
|
|
3.7
|
|
—
|
|
6.7
|
|
|||||
Insufficient coverage
|
$
|
738,796
|
|
$
|
—
|
|
$
|
—
|
|
$
|
86,557
|
|
$
|
—
|
|
A.
|
Wholly-owned subsidiaries of SM Energy Company, a Delaware corporation:
|
B.
|
Partnership or limited liability company interests held by SM Energy Company:
|
1.
|
Potato Creek Midstream, LLC, a Pennsylvania limited liability company (70%)
|
2.
|
1977 H.B Joint Account, a Colorado general partnership (8%)
|
3.
|
1976 H.B Joint Account, a Colorado general partnership (9%)
|
4.
|
1974 H.B Joint Account, a Colorado general partnership (4%)
|
1.
|
St. Mary Land East Texas LP, a Texas limited partnership (99%) (the remaining 1% interest is held by SM Energy Company)
|
1.
|
I have reviewed this annual report on Form 10-K of SM Energy Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
1.
|
I have reviewed this annual report on Form 10-K of SM Energy Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
/s/ Michael F. Stell
|
|
/s/ James L. Baird
|
Michael F. Stell, P.E.
|
|
James L. Baird
|
TBPE License No. 56416
|
|
Colorado License No. 41521
|
Advising Senior Vice President
|
|
Managing Senior Vice President
|
As of December 31, 2015
|
|
|
Proved
|
||||||
|
|
Developed
|
|
|
|
Total
|
||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
Net Reserves of Properties
Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBarrels
|
|
53,478
|
|
1,136
|
|
52,958
|
|
107,572
|
Plant Products - MBarrels
|
|
56,695
|
|
609
|
|
53,627
|
|
110,931
|
Gas - MMCF
|
|
555,697
|
|
4,113
|
|
559,282
|
|
1,119,092
|
|
|
|
|
|
|
|
|
|
Net Reserves of Properties
Not Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBarrels
|
|
20,340
|
|
685
|
|
16,667
|
|
37,692
|
Plant Products - MBarrels
|
|
3,471
|
|
700
|
|
262
|
|
4,433
|
Gas - MMCF
|
|
76,988
|
|
7,571
|
|
60,397
|
|
144,956
|
|
|
|
|
|
|
|
|
|
Total Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBarrels
|
|
73,818
|
|
1,821
|
|
69,625
|
|
145,264
|
Plant Products - MBarrels
|
|
60,166
|
|
1,309
|
|
53,889
|
|
115,364
|
Gas - MMCF
|
|
632,685
|
|
11,684
|
|
619,679
|
|
1,264,048
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|