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Delaware
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46-3472728
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(State or Other Jurisdiction of
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(I.R.S. Employer
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Incorporation or Organization)
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Identification No.)
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1001 Louisiana Street
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Houston, Texas
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77002
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(Address of Principal Executive Offices)
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(Zip Code)
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Name of Each Exchange
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Title of Each Class
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on which Registered
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Class A Common Stock,
par value $0.01 per share
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New York Stock Exchange
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Large accelerated filer
o
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Accelerated filer
x
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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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/d
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=
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per day
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Bbl
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=
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barrel
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Bcf
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=
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billion cubic feet
|
Boe
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=
|
barrel of oil equivalent
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CBM
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=
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coal bed methane
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Gal
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=
|
gallons
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LLS
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=
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light Louisiana Sweet crude oil
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LNG
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=
|
liquefied natural gas
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MBoe
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=
|
thousand barrels of oil equivalent
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MBbls
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=
|
thousand barrels
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Mcf
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=
|
thousand cubic feet
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MMGal
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=
|
million gallons
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MMBtu
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=
|
million British thermal units
|
MMBoe
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=
|
million barrels of oil equivalent
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MMBbls
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=
|
million barrels
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MMcf
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=
|
million cubic feet
|
MMcfe
|
=
|
million cubic feet of natural gas equivalents
|
NGLs
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=
|
natural gas liquids
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TBtu
|
=
|
trillion British thermal units
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WTI
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=
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West Texas intermediate
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•
|
our ability to obtain necessary governmental approvals for proposed exploration and production projects and to successfully construct and operate such projects;
|
•
|
credit and performance risks of our lenders, trading counterparties, customers, vendors, suppliers and third party operators;
|
•
|
general economic and weather conditions in geographic regions or markets we serve, or where operations are located, including the risk of a global recession and negative impact on demand for oil and/or natural gas;
|
•
|
the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulations;
|
•
|
the other factors described under Item 1A, “Risk Factors,” on pages 16 through 34 of this Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
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|
Estimated Proved Reserves
(1)
|
|
|
|||||||||||||||||
|
Oil
(MMBbls)
|
|
NGLs
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
Total
(MMBoe)
|
|
Liquids
(%)
|
|
Proved
Developed
(%)
|
|
Average
Net Daily
Production
(MBoe/d)
|
|||||||
Eagle Ford Shale
|
156.0
|
|
|
52.0
|
|
|
313.4
|
|
|
260.2
|
|
|
80
|
%
|
|
42
|
%
|
|
58.2
|
|
Wolfcamp Shale
|
63.8
|
|
|
38.9
|
|
|
249.6
|
|
|
144.3
|
|
|
71
|
%
|
|
39
|
%
|
|
19.9
|
|
Altamont
|
78.9
|
|
|
—
|
|
|
170.2
|
|
|
107.3
|
|
|
74
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%
|
|
54
|
%
|
|
17.1
|
|
Haynesville Shale
|
—
|
|
|
—
|
|
|
205.0
|
|
|
34.2
|
|
|
—
|
%
|
|
100
|
%
|
|
14.4
|
|
Other
(2)
|
—
|
|
|
—
|
|
|
0.2
|
|
|
—
|
|
|
—
|
%
|
|
100
|
%
|
|
0.1
|
|
Total
(3)
|
298.7
|
|
|
90.9
|
|
|
938.4
|
|
|
546.0
|
|
|
71
|
%
|
|
47
|
%
|
|
109.7
|
|
|
(1)
|
Proved reserves were evaluated based on the average first day of the month spot price for the preceding 12-month period of
$50.28
per Bbl (WTI) and
$2.59
per MMBtu (Henry Hub). The spot prices at December 31, 2015, were $37.04 per Bbl and $2.34 per MMBtu.
|
(2)
|
Estimated proved reserves are comprised of outside operated overriding interests in the Gulf of Mexico and Rockies. Average net daily production is comprised of outside operated overriding interests in the Gulf of Mexico, Rockies and East Texas/North Louisiana.
|
|
Acres
|
|
Drilling
Locations
(1)
(#)
|
|
2015
Drilling
Locations
(2)
(#)
|
|
Inventory
(Years)
(3)
|
|
Working
Interest
(%)
|
|
Net
Revenue
Interest
(%)
|
|||||||||
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Gross
|
|
Net
|
|
|
|
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|
||||||||||||
Eagle Ford Shale
|
106,054
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|
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94,153
|
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|
973
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|
|
118
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|
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8.2
|
|
|
83
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%
|
|
62
|
%
|
Wolfcamp Shale
|
178,281
|
|
|
178,111
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|
|
3,264
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|
|
36
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|
|
90.7
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|
|
97
|
%
|
|
72
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%
|
Wolfcamp A
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|
|
|
|
1,161
|
|
|
|
|
|
|
96
|
%
|
|
72
|
%
|
||||
Wolfcamp B
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|
|
|
|
1,006
|
|
|
|
|
|
|
96
|
%
|
|
72
|
%
|
||||
Wolfcamp C
|
|
|
|
|
1,097
|
|
|
|
|
|
|
97
|
%
|
|
73
|
%
|
||||
Altamont
|
323,214
|
|
|
180,944
|
|
|
1,282
|
|
|
30
|
|
|
42.7
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|
|
73
|
%
|
|
62
|
%
|
Haynesville Shale
|
52,933
|
|
|
34,167
|
|
|
190
|
|
|
4
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|
|
47.6
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|
|
76
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%
|
|
61
|
%
|
Holly
|
|
|
|
|
142
|
|
|
|
|
|
|
74
|
%
|
|
59
|
%
|
||||
Non-Holly
|
|
|
|
|
48
|
|
|
|
|
|
|
86
|
%
|
|
68
|
%
|
||||
Total
|
660,482
|
|
|
487,375
|
|
|
5,709
|
|
|
188
|
|
|
30.4
|
|
|
88
|
%
|
|
68
|
%
|
|
•
|
In the Wolfcamp Shale area, (i) horizontal drilling locations in the Cline Shale and (ii) vertical drilling locations in the Spraberry and other stacked formations; and
|
•
|
In Altamont, (i) additional vertical infill locations and (ii) horizontal drilling locations in the Wasatch and Green River formations.
|
|
Net Proved Reserves
(1)
|
|||||||||||||
|
Oil
(MMBbls)
|
|
NGLs
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
Total
(MMBoe)
|
|
Percent
(%)
|
|||||
Reserves by Classification
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford Shale
|
68.9
|
|
|
19.9
|
|
|
120.3
|
|
|
108.9
|
|
|
20
|
%
|
Wolfcamp Shale
|
21.8
|
|
|
16.6
|
|
|
106.6
|
|
|
56.1
|
|
|
10
|
%
|
Altamont
|
41.1
|
|
|
—
|
|
|
97.8
|
|
|
57.4
|
|
|
11
|
%
|
Haynesville Shale
|
—
|
|
|
—
|
|
|
205.0
|
|
|
34.2
|
|
|
6
|
%
|
Other
(2)
|
—
|
|
|
—
|
|
|
0.2
|
|
|
—
|
|
|
—
|
%
|
Total Proved Developed
(3)
|
131.8
|
|
|
36.5
|
|
|
529.9
|
|
|
256.6
|
|
|
47
|
%
|
Proved Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford Shale
|
87.1
|
|
|
32.1
|
|
|
193.0
|
|
|
151.3
|
|
|
28
|
%
|
Wolfcamp Shale
|
42.0
|
|
|
22.3
|
|
|
143.1
|
|
|
88.2
|
|
|
16
|
%
|
Altamont
|
37.8
|
|
|
—
|
|
|
72.4
|
|
|
49.9
|
|
|
9
|
%
|
Haynesville Shale
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
%
|
Other
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
%
|
Total Proved Undeveloped
|
166.9
|
|
|
54.4
|
|
|
408.5
|
|
|
289.4
|
|
|
53
|
%
|
Total Proved Reserves
|
298.7
|
|
|
90.9
|
|
|
938.4
|
|
|
546.0
|
|
|
100
|
%
|
|
(1)
|
Proved reserves were evaluated based on the average first day of the month spot price for the preceding 12-month period of
$50.28
per Bbl (WTI) and
$2.59
per MMBtu (Henry Hub).
|
(3)
|
Includes 242 MMBoe of proved developed producing reserves representing 44% of total net proved reserves and 15 MMBoe of proved developed non-producing reserves representing 3% of total net proved reserves at
December 31, 2015
.
|
|
Net Proved Reserves
(MMBoe)
|
|
As Reported
|
546.0
|
|
10 percent increase in commodity prices
|
553.6
|
|
10 percent decrease in commodity prices
|
393.5
|
|
Balance, December 31, 2013
|
365
|
|
Purchase of minerals in place
|
3
|
|
Extensions and discoveries
(1)
|
75
|
|
Revisions due to prices
|
34
|
|
Revisions other than prices
(2)
|
(10
|
)
|
Transfers to proved developed
|
(75
|
)
|
Divestitures
|
(8
|
)
|
Balance, December 31, 2014
|
384
|
|
Purchase of minerals in place
|
6
|
|
Extensions and discoveries
|
58
|
|
Revisions due to prices
|
(3
|
)
|
Revisions other than prices
|
(101
|
)
|
Transfers to proved developed
|
(55
|
)
|
Balance, December 31, 2015
|
289
|
|
|
|
Developed
|
|
Undeveloped
|
|
Total
|
||||||||||||
|
Gross
(1)
|
|
Net
(2)
|
|
Gross
(1)
|
|
Net
(2)
|
|
Gross
(1)
|
|
Net
(2)
|
||||||
Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford Shale
|
38,065
|
|
|
34,101
|
|
|
67,989
|
|
|
60,052
|
|
|
106,054
|
|
|
94,153
|
|
Wolfcamp Shale
|
16,762
|
|
|
16,598
|
|
|
161,519
|
|
|
161,513
|
|
|
178,281
|
|
|
178,111
|
|
Altamont
|
87,603
|
|
|
65,126
|
|
|
235,611
|
|
|
115,818
|
|
|
323,214
|
|
|
180,944
|
|
Haynesville Shale
|
16,950
|
|
|
11,283
|
|
|
35,983
|
|
|
22,884
|
|
|
52,933
|
|
|
34,167
|
|
Other
|
102,949
|
|
|
8,036
|
|
|
278,715
|
|
|
155,380
|
|
|
381,664
|
|
|
163,416
|
|
Total Acreage
|
262,329
|
|
|
135,144
|
|
|
779,817
|
|
|
515,647
|
|
|
1,042,146
|
|
|
650,791
|
|
|
|
Oil
|
|
Natural Gas
|
|
Total
|
|
Wells Being
Drilled at
December 31,
2015
(1)
|
||||||||||||||||
|
Gross
(2)
|
|
Net
(3)
|
|
Gross
(2)
|
|
Net
(3)
|
|
Gross
(2)
|
|
Net
(3)(4)
|
|
Gross
(2)
|
|
Net
(3)
|
||||||||
Productive Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford Shale
|
637
|
|
|
568
|
|
|
3
|
|
|
3
|
|
|
640
|
|
|
571
|
|
|
49
|
|
|
48
|
|
Wolfcamp Shale
|
243
|
|
|
240
|
|
|
—
|
|
|
—
|
|
|
243
|
|
|
240
|
|
|
36
|
|
|
36
|
|
Altamont
|
500
|
|
|
386
|
|
|
3
|
|
|
1
|
|
|
503
|
|
|
387
|
|
|
8
|
|
|
7
|
|
Haynesville Shale
|
—
|
|
|
—
|
|
|
219
|
|
|
110
|
|
|
219
|
|
|
110
|
|
|
—
|
|
|
—
|
|
Total Productive Wells
|
1,380
|
|
|
1,194
|
|
|
225
|
|
|
114
|
|
|
1,605
|
|
|
1,308
|
|
|
93
|
|
|
91
|
|
|
|
Net Exploratory
(1)
|
|
Net Development
(1)
|
||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2015
|
|
2014
|
|
2013
|
||||||
Wells Drilled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
—
|
|
|
5
|
|
|
8
|
|
|
180
|
|
|
257
|
|
|
216
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Total Wells Drilled
|
—
|
|
|
5
|
|
|
8
|
|
|
180
|
|
|
257
|
|
|
218
|
|
|
|
(1)
|
Volumes in 2013 represent volumes from our approximate 49% equity interest in the volumes of Four Star Oil & Gas Company (Four Star), which we sold in September 2013.
|
|
2015
|
|
2014
|
|
2013
|
||||||
Net Production Volumes by Area
|
|
|
|
|
|
|
|
|
|||
Eagle Ford Shale
|
|
|
|
|
|
|
|
|
|||
Oil (MBbls)
|
14,220
|
|
|
12,698
|
|
|
8,763
|
|
|||
Natural Gas (MMcf)
|
21,212
|
|
|
18,215
|
|
|
14,857
|
|
|||
NGLs (MBbls)
|
3,483
|
|
|
2,851
|
|
|
2,133
|
|
|||
Total Eagle Ford Shale (MBoe)
|
21,238
|
|
|
18,585
|
|
|
13,372
|
|
|||
Wolfcamp Shale
|
|
|
|
|
|
|
|
||||
Oil (MBbls)
|
3,321
|
|
|
3,073
|
|
|
1,306
|
|
|||
Natural Gas (MMcf)
|
12,317
|
|
|
7,551
|
|
|
2,483
|
|
|||
NGLs (MBbls)
|
1,870
|
|
|
1,237
|
|
|
280
|
|
|||
Total Wolfcamp Shale (MBoe)
|
7,244
|
|
|
5,568
|
|
|
2,000
|
|
|||
Altamont
|
|
|
|
|
|
|
|
||||
Oil (MBbls)
|
4,532
|
|
|
4,208
|
|
|
3,161
|
|
|||
Natural Gas (MMcf)
|
10,299
|
|
|
8,504
|
|
|
6,931
|
|
|||
NGLs (MBbls)
|
9
|
|
|
21
|
|
|
11
|
|
|||
Total Altamont (MBoe)
|
6,257
|
|
|
5,646
|
|
|
4,327
|
|
|||
Haynesville Shale
|
|
|
|
|
|
|
|
||||
Oil (MBbls)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Natural Gas (MMcf)
|
31,521
|
|
|
34,907
|
|
|
59,335
|
|
|||
NGLs (MBbls)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total Haynesville Shale (MBoe)
|
5,253
|
|
|
5,818
|
|
|
9,889
|
|
|||
|
|
|
|
|
|
||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Prices and Costs per Unit:
(1)(2)
|
|
|
|
|
|
|
|
|
|||
Oil Average Realized Sales Price ($/Bbl)
|
|
|
|
|
|
|
|
|
|||
Physical Sales
|
$
|
44.28
|
|
|
$
|
85.31
|
|
|
$
|
94.75
|
|
Including Financial Derivatives
(3)
|
$
|
82.18
|
|
|
$
|
88.77
|
|
|
$
|
97.56
|
|
Natural Gas Average Realized Sales Price ($/Mcf)
|
|
|
|
|
|
|
|
||||
Physical Sales
|
$
|
2.27
|
|
|
$
|
3.76
|
|
|
$
|
3.28
|
|
Including Financial Derivatives
(3)
|
$
|
3.59
|
|
|
$
|
3.34
|
|
|
$
|
2.97
|
|
NGLs Average Realized Sales Price ($/Bbl)
|
|
|
|
|
|
|
|
|
|||
Physical Sales
|
$
|
11.22
|
|
|
$
|
26.73
|
|
|
$
|
30.58
|
|
Including Financial Derivatives
(3)
|
$
|
12.36
|
|
|
$
|
27.78
|
|
|
$
|
—
|
|
Average Transportation Costs
|
|
|
|
|
|
|
|
|
|||
Oil ($/Bbl)
|
$
|
1.55
|
|
|
$
|
1.65
|
|
|
$
|
2.01
|
|
Natural Gas ($/Mcf)
|
$
|
0.91
|
|
|
$
|
0.65
|
|
|
$
|
0.52
|
|
NGLs ($/Bbl)
|
$
|
2.31
|
|
|
$
|
5.42
|
|
|
$
|
6.07
|
|
Average Lease Operating Expenses ($/Boe)
|
$
|
4.64
|
|
|
$
|
5.40
|
|
|
$
|
4.98
|
|
Average Production Taxes ($/Boe)
|
$
|
1.83
|
|
|
$
|
3.39
|
|
|
$
|
2.84
|
|
|
(2)
|
Oil prices for the year ended
December 31, 2015
are calculated including a reduction of $3 million for oil purchases associated with managing our physical sales. Natural gas prices for the years ended
December 31, 2015
,
2014
and
2013
are calculated including a reduction of $28 million,
$23 million
and
$25 million
, respectively, for natural gas purchases associated with managing our physical sales.
|
(3)
|
Amounts reflect settlements on financial derivatives, including cash premiums. No cash premiums were received or paid for the year ended December 31, 2015. For the years ended December 31, 2014 and 2013, we received approximately $1 million and $9 million of cash premiums, respectively.
|
•
|
Our drilling process executes several repeated cycles conducted in sequence—drill, set casing, cement casing and then test casing and cement for integrity before proceeding to the next drilling interval.
|
•
|
Conductor casing is drilled and cemented or driven in place. This string serves as the structural foundation for the well. Conductor casing is not necessary or required for all wells.
|
•
|
Surface casing is set and is cemented in place. Surface casing is set on all wells. The purpose of the surface casing is to isolate and protect Underground Sources of Drinking Water (USDW) as identified by federal and state regulatory bodies. The surface casing and cement isolates wellbore materials from any potential contact with USDWs.
|
•
|
Intermediate casing is set through the surface casing to a depth necessary to isolate abnormally pressured subsurface formations from normally pressured formations. Intermediate casing is not necessary or required for all wells. Our standard practices include cementing above any hydrocarbon bearing zone and performing casing pressure tests to verify the integrity of the casing and cement.
|
•
|
Production casing is set through the surface and intermediate casing through the depth of the targeted producing formation. Our standard practices include pumping cement above the confining structure of the target zone and performing casing pressure tests and other tests to verify the integrity of the casing and cement. If any problems are detected, then appropriate remedial action is taken.
|
•
|
With the casing set and cemented, a barrier of steel and cement is in place that is designed to isolate the wellbore from surrounding geologic formations. This barrier as designed mitigates against the risk of drilling or fracturing fluids entering potential sources of drinking water.
|
Name
|
|
Office
|
|
Age
|
Brent J. Smolik
|
|
President, Chief Executive Officer and Chairman of the Board
|
|
54
|
Clayton A. Carrell
|
|
Executive Vice President and Chief Operating Officer
|
|
50
|
Joan M. Gallagher
|
|
Senior Vice President, Human Resources and Administrative Services
|
|
52
|
Dane E. Whitehead
|
|
Executive Vice President and Chief Financial Officer
|
|
54
|
Marguerite N. Woung-Chapman
|
|
Senior Vice President, General Counsel and Corporate Secretary
|
|
50
|
•
|
regional, domestic and international supply of, and demand for, oil, natural gas and NGLs;
|
•
|
oil, natural gas and NGLs inventory levels in the United States;
|
•
|
political and economic conditions domestically and in other oil and natural gas producing countries, including the current conflicts in the Middle East and conditions in Africa, Russia and South America;
|
•
|
actions of OPEC and other state-controlled oil companies relating to oil, natural gas and NGLs price and production controls;
|
•
|
wars, terrorist activities and other acts of aggression;
|
•
|
weather conditions and weather patterns;
|
•
|
technological advances affecting energy consumption and energy supply;
|
•
|
adoption of various energy efficiency and conservation measures;
|
•
|
the price and availability of supplies of alternative energy sources;
|
•
|
the price and quantity of U.S. imports and exports of oil, natural gas, including liquefied natural gas, and NGLs;
|
•
|
volatile trading patterns in capital and commodity-futures markets;
|
•
|
the strengthening and weakening of the U.S. dollar relative to other currencies;
|
•
|
changes in domestic governmental regulations, administrative and/or agency actions, and taxes, including potential restrictive regulations associated with hydraulic fracturing operations;
|
•
|
changes in the costs of exploring for, developing, producing, transporting, processing and marketing oil, natural gas and NGLs;
|
•
|
availability, proximity and cost of commodity processing, gathering and transportation and refining capacity;
|
•
|
perceptions of customers on the availability and price volatility of our products, particularly customers' perception of the volatility of oil and natural gas prices over the longer term; and
|
•
|
variations between product prices at sales points and applicable index prices.
|
•
|
unexpected drilling conditions;
|
•
|
delays imposed by or resulting from compliance with regulatory and contractual requirements;
|
•
|
unexpected pressure or irregularities in geological formations;
|
•
|
equipment failures or accidents;
|
•
|
fracture stimulation accidents or failures;
|
•
|
adverse weather conditions;
|
•
|
declines in oil and natural gas prices;
|
•
|
surface access restrictions with respect to drilling or laying pipelines;
|
•
|
shortages (or increases in costs) of water used in hydraulic fracturing, especially in arid regions or regions that have been experiencing severe drought conditions;
|
•
|
shortages or delays in the availability of, increases in the cost of, or increased competition for, drilling rigs and crews, fracture stimulation crews, equipment, pipe, chemicals and supplies and transportation, gathering, processing, treating or other midstream services; and
|
•
|
limitations or reductions in the market for oil and natural gas.
|
•
|
when production is less than expected or less than we have hedged;
|
•
|
when the counterparty to the hedging instrument defaults on its contractual obligations;
|
•
|
when there is an increase in the differential between the underlying price in the hedging instrument and actual prices received; and
|
•
|
when there are issues with respect to legal enforceability of such instruments.
|
•
|
Adverse weather conditions, natural disasters, and/or other climate related matters
—including extreme cold or heat, lightning and flooding, fires, earthquakes, hurricanes, tornadoes and other natural disasters. Although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could also have a negative impact upon our operations in the future, particularly with regard to any of our facilities that are located in or near coastal regions;
|
•
|
Acts of aggression on critical energy infrastructure
—including terrorist activity or “cyber security” events. We are subject to the ongoing risk that one of these incidents may occur which could significantly impact our business operations and/or financial results. Should one of these events occur in the future, it could impact our ability to operate our drilling and exploration processes, our operations could be disrupted, and/or property could be damaged resulting in substantial loss of revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation and litigation and/or inaccurate information reported from our exploration and production operations to our financial applications, to our customers and to regulatory entities; and
|
•
|
Other hazards
—including the collision of third-party equipment with our infrastructure; explosions, equipment malfunctions, mechanical and process safety failures, well blowouts, formations with abnormal pressures and collapses of wellbore casing or other tubulars; events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, oil, brine or well fluids, release of pollution or contaminants (including hydrocarbons) into the environment (including discharges of toxic gases or substances) and other environmental hazards.
|
•
|
the location of wells;
|
•
|
methods of drilling and completing wells;
|
•
|
allowable production from wells;
|
•
|
unitization or pooling of oil and gas properties;
|
•
|
spill prevention plans;
|
•
|
limitations on venting or flaring of natural gas;
|
•
|
disposal of fluids used and wastes generated in connection with operations;
|
•
|
access to, and surface use and restoration of, well properties;
|
•
|
plugging and abandoning of wells, even if we no longer own and/or operate such wells;
|
•
|
air quality and emissions, noise levels and related permits;
|
•
|
gathering, transportation and marketing of oil and natural gas (including NGLs);
|
•
|
taxation; and
|
•
|
competitive bidding rules on federal and state lands.
|
•
|
we cannot obtain future permits from applicable regulatory agencies;
|
•
|
water of lesser quality or requiring additional treatment is produced;
|
•
|
our wells produce excess water;
|
•
|
new laws and regulations require water to be disposed in a different manner; or
|
•
|
costs to transport the produced water to the disposal wells increase.
|
•
|
we may not produce revenues, reserves, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;
|
•
|
we may assume liabilities that were not disclosed to us and for which contractual protections prove inadequate or that exceed our estimates;
|
•
|
we may acquire properties that are subject to burdens on title that we were not aware of at the time of acquisition that interfere with our ability to hold the property for production and for which contractual protections prove inadequate;
|
•
|
we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
|
•
|
we may encounter disruption to our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls, procedures and policies;
|
•
|
we may issue (or assume) additional equity or debt securities or debt instruments in connection with future acquisitions, which may affect our liquidity or financial leverage;
|
•
|
we may make mistaken assumptions about costs, including synergies related to an acquired business;
|
•
|
we may encounter difficulties in complying with regulations, such as environmental regulations, and managing risks related to an acquired business;
|
•
|
we may encounter limitations on rights to indemnity from the seller;
|
•
|
we may make mistaken assumptions about the overall costs of equity or debt used to finance any such acquisition;
|
•
|
we may encounter difficulties in entering markets in which we have no or limited direct prior experience and where competitors in such markets have stronger expertise and/or market positions;
|
•
|
we may potentially lose key customers; and
|
•
|
we may lose key employees and/or encounter costly litigation resulting from the termination of those employees.
|
•
|
the repeal of the percentage depletion allowance for oil and gas properties;
|
•
|
the elimination of current expensing of intangible drilling and development costs;
|
•
|
the elimination of the deduction for certain U.S. production activities; and
|
•
|
an extension of the amortization period for certain geological and geophysical expenditures.
|
•
|
incur additional debt, guarantee indebtedness or issue certain preferred shares;
|
•
|
pay dividends on or make distributions in respect of, or repurchase or redeem, our capital stock or make other restricted payments;
|
•
|
prepay, redeem or repurchase certain debt;
|
•
|
make loans or certain investments;
|
•
|
sell certain assets;
|
•
|
create liens on certain assets;
|
•
|
consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
|
•
|
enter into certain transactions with our affiliates;
|
•
|
alter the businesses we conduct;
|
•
|
enter into agreements restricting our subsidiaries’ ability to pay dividends; and
|
•
|
designate our subsidiaries as unrestricted subsidiaries.
|
•
|
will not be required to lend any additional amounts to us;
|
•
|
could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable and terminate all commitments to extend further credit; or
|
•
|
could require us to apply all of our available cash to repay these borrowings.
|
|
|
2015
|
|
2014
|
||||||||||||
|
|
High
|
|
Low
|
|
High
|
|
Low
|
||||||||
Fourth Quarter
|
|
$
|
7.82
|
|
|
$
|
3.48
|
|
|
$
|
16.79
|
|
|
$
|
7.16
|
|
Third Quarter
|
|
11.56
|
|
|
4.85
|
|
|
22.55
|
|
|
16.98
|
|
||||
Second Quarter
|
|
15.21
|
|
|
10.78
|
|
|
23.05
|
|
|
18.30
|
|
||||
First Quarter
|
|
13.36
|
|
|
8.71
|
|
|
19.73
|
|
|
16.82
|
|
|
|
March 31,
2015
|
|
June 30,
2015
|
|
September 30,
2015
|
|
December 31,
2015
|
||||||||
EP Energy Corporation
|
|
$
|
57.96
|
|
|
$
|
70.41
|
|
|
$
|
28.48
|
|
|
$
|
24.23
|
|
S&P 500 Index
|
|
115.28
|
|
|
115.60
|
|
|
108.16
|
|
|
115.77
|
|
||||
Dow Jones U.S. Exploration and Production Index
|
|
94.69
|
|
|
91.75
|
|
|
72.72
|
|
|
70.00
|
|
|
|
January 17, 2014
|
|
March 31,
2014
|
|
June 30,
2014
|
|
September 30,
2014
|
|
December 31,
2014
|
||||||||||
EP Energy Corporation
|
|
$
|
100.00
|
|
|
$
|
108.24
|
|
|
$
|
127.49
|
|
|
$
|
96.68
|
|
|
$
|
57.74
|
|
S&P 500 Index
|
|
100.00
|
|
|
102.27
|
|
|
107.62
|
|
|
108.84
|
|
|
114.20
|
|
|||||
Dow Jones U.S. Exploration and Production Index
|
|
100.00
|
|
|
106.58
|
|
|
121.90
|
|
|
110.28
|
|
|
91.79
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||||
|
Year ended
December 31,
|
|
Year ended
December 31,
|
|
Year ended
December 31,
|
|
February 14
to
December 31,
|
|
|
January 1,
to May 24,
|
|
Year ended
December 31,
|
||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
|
2012
|
|
2011
|
||||||||||||
|
|
|
(in millions, except per common share amounts)
|
|||||||||||||||||||||
Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Operating revenues
|
$
|
1,908
|
|
|
$
|
3,084
|
|
|
$
|
1,576
|
|
|
$
|
681
|
|
|
|
$
|
932
|
|
|
$
|
1,756
|
|
Impairment and ceiling test charges
|
4,299
|
|
|
2
|
|
|
2
|
|
|
1
|
|
|
|
62
|
|
|
6
|
|
||||||
Operating (loss) income
|
(3,955
|
)
|
|
1,493
|
|
|
383
|
|
|
(72
|
)
|
|
|
338
|
|
|
648
|
|
||||||
Interest expense
|
(330
|
)
|
|
(318
|
)
|
|
(354
|
)
|
|
(219
|
)
|
|
|
(14
|
)
|
|
(14
|
)
|
||||||
(Loss) income from continuing operations
|
(3,748
|
)
|
|
727
|
|
|
(56
|
)
|
|
(306
|
)
|
|
|
187
|
|
|
385
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Basic and diluted net income (loss) per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
(Loss) income from continuing operations
|
$
|
(15.37
|
)
|
|
$
|
3.00
|
|
|
$
|
(0.27
|
)
|
|
$
|
(1.46
|
)
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Operating activities
|
$
|
1,327
|
|
|
$
|
1,186
|
|
|
$
|
960
|
|
|
$
|
449
|
|
|
|
$
|
580
|
|
|
$
|
1,426
|
|
Investing activities
|
(1,543
|
)
|
|
(2,044
|
)
|
|
(475
|
)
|
|
(7,893
|
)
|
|
|
(628
|
)
|
|
(1,237
|
)
|
||||||
Financing activities
|
220
|
|
|
829
|
|
|
(503
|
)
|
|
7,513
|
|
|
|
110
|
|
|
(238
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
As of December 31,
|
|
|
|||||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
|
2011
|
|
|
||||||||||||
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
||||||||||||
Financial Position
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total assets
|
$
|
5,833
|
|
|
$
|
10,154
|
|
|
$
|
8,257
|
|
|
$
|
8,212
|
|
|
|
$
|
5,103
|
|
|
|
||
Long-term debt
|
4,812
|
|
|
4,533
|
|
|
4,340
|
|
|
4,601
|
|
|
|
851
|
|
|
|
|||||||
Stockholders’/ Member’s equity
|
619
|
|
|
4,348
|
|
|
2,937
|
|
|
2,748
|
|
|
|
3,100
|
|
|
|
•
|
maintaining and growing our proved reserve base and production volumes through the successful execution of our drilling programs or through acquisitions;
|
•
|
finding and producing oil and natural gas at reasonable costs;
|
•
|
managing cash costs; and
|
•
|
managing commodity price risks on our oil and natural gas production.
|
|
2016
|
|
2017
|
||||||||||
|
Volumes
(1)
|
|
Average
Price
(1)
|
|
Volumes
(1)
|
|
Average
Price
(1)
|
||||||
Oil
|
|
|
|
|
|
|
|
|
|
||||
Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
||||
WTI
|
8,510
|
|
|
$
|
80.03
|
|
|
4,015
|
|
|
$
|
66.11
|
|
LLS
|
9,516
|
|
|
$
|
80.51
|
|
|
—
|
|
|
$
|
—
|
|
Three Way Collars
|
|
|
|
|
|
|
|
||||||
Ceiling - WTI
|
—
|
|
|
$
|
—
|
|
|
1,095
|
|
|
$
|
75.13
|
|
Floors - WTI
(2)
|
—
|
|
|
$
|
—
|
|
|
1,095
|
|
|
$
|
65.00
|
|
Basis Swaps
|
|
|
|
|
|
|
|
||||||
LLS vs. WTI
(3)
|
2,013
|
|
|
$
|
3.91
|
|
|
—
|
|
|
$
|
—
|
|
LLS vs. Brent
(4)
|
2,196
|
|
|
$
|
(4.99
|
)
|
|
3,650
|
|
|
$
|
(3.14
|
)
|
Midland vs. Cushing
(5)
|
732
|
|
|
$
|
(0.83
|
)
|
|
1,460
|
|
|
$
|
(0.68
|
)
|
WTI - CM vs. TM
(6)
|
11,712
|
|
|
$
|
0.31
|
|
|
—
|
|
|
$
|
—
|
|
NYMEX Roll
(7)
|
8,230
|
|
|
$
|
(0.86
|
)
|
|
—
|
|
|
$
|
—
|
|
Natural Gas
|
|
|
|
|
|
|
|
||||||
Fixed Price Swaps
|
7
|
|
|
$
|
4.20
|
|
|
—
|
|
|
$
|
—
|
|
Propane
|
|
|
|
|
|
|
|
||||||
Fixed Price Swaps
|
15
|
|
|
$
|
0.55
|
|
|
—
|
|
|
$
|
—
|
|
|
(7)
|
These positions hedge the timing risk associated with our physical sales. We generally sell oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the "trade month roll").
|
•
|
Capital expenditures of approximately $500 million to $900 million.
|
•
|
Average daily production volumes for the year of approximately 91 MBoe/d to 97 MBoe/d, including average daily oil production volumes of approximately 45 MBbls/d to 50 MBbls/d.
|
•
|
Per unit adjusted cash operating costs for the year of approximately $9.50 to $10.50 per Boe, and transportation costs of $3.40 to $3.65 per Boe.
|
|
2015
|
|
2014
|
|
2013
|
|||
United States (MBoe/d)
|
|
|
|
|
|
|
|
|
Eagle Ford Shale
|
58.2
|
|
|
50.9
|
|
|
36.6
|
|
Wolfcamp Shale
|
19.9
|
|
|
15.3
|
|
|
5.5
|
|
Altamont
|
17.1
|
|
|
15.5
|
|
|
11.9
|
|
Haynesville Shale
|
14.4
|
|
|
15.9
|
|
|
27.1
|
|
Other
|
0.1
|
|
|
0.1
|
|
|
0.1
|
|
Divested assets
(1)
|
—
|
|
|
—
|
|
|
6.0
|
|
Total
|
109.7
|
|
|
97.7
|
|
|
87.2
|
|
|
|
|
|
|
|
|||
Oil (MBbls/d)
|
|
|
|
|
|
|
|
|
Consolidated volumes
|
60.5
|
|
|
54.8
|
|
|
36.2
|
|
Divested assets
(1)
|
—
|
|
|
—
|
|
|
0.5
|
|
Total Combined
|
60.5
|
|
|
54.8
|
|
|
36.7
|
|
Natural Gas (MMcf/d)
|
|
|
|
|
|
|
|
|
Consolidated volumes
|
207
|
|
|
190
|
|
|
230
|
|
Divested assets
(1)
|
—
|
|
|
—
|
|
|
28
|
|
Total Combined
|
207
|
|
|
190
|
|
|
258
|
|
NGLs (MBbls/d)
|
|
|
|
|
|
|
|
|
Consolidated volumes
|
14.7
|
|
|
11.3
|
|
|
6.7
|
|
Divested assets
(1)
|
—
|
|
|
—
|
|
|
0.9
|
|
Total Combined
|
14.7
|
|
|
11.3
|
|
|
7.6
|
|
|
(1)
|
Represents production volumes from Four Star Oil & Gas Company (Four Star), our equity investment sold in September 2013.
|
•
|
Eagle Ford Shale
—Our Eagle Ford Shale equivalent volumes and oil production increased
7.3
MBoe/d (approximately
14%
) and
4.2
MBbls/d (
12%
), respectively, for the year ended
December 31, 2015
compared to
2014
due to the success of our drilling program in the area. During
2015
, we completed
118
additional operated wells in the Eagle Ford, and we had a total of 563 net operated wells as of
December 31, 2015
(which includes wells acquired in September 2015). A majority of our acreage is located in the core of the oil window, primarily in LaSalle County.
|
•
|
Wolfcamp Shale
—Our Wolfcamp Shale equivalent volumes increased
4.6
MBoe/d (approximately
30%
) for the year ended
December 31, 2015
compared to
2014
as we continued to progress the development of the program. During
2015
, we completed
36
additional operated wells, for a total of 237 net operated wells as of
December 31, 2015
.
|
•
|
Altamont
—Our Altamont equivalent volumes increased
1.6
MBoe/d (approximately
10%
) for the year ended
December 31, 2015
compared to
2014
. Altamont produced an average of
12.4
MBbls/d of oil during
2015
, and we completed an additional
30
operated oil wells for a total of 378 net operated wells at
December 31, 2015
.
|
•
|
Haynesville Shale
—Our Haynesville Shale equivalent volumes decreased
1.5
MMcf/d (approximately
9%
) for the year ended
December 31, 2015
compared to
2014
, due to natural production declines. In
2015
, we began testing the impact of current completion and refracking techniques on well performance and financial returns. As of
December 31, 2015
, we had completed
4
additional operated wells for a total of 103 net operated wells in the Haynesville Shale, and our total natural gas production for
2015
was approximately
87
MMcf/d.
|
Reserve replacement ratio
|
|
Sum of reserve additions
(1)
|
|
|
Actual production for the corresponding period
|
|
|
|
Reserve replacement costs/Boe
|
|
Total oil and natural gas capital costs
(2)
|
|
|
Sum of reserve additions
(1)
|
|
(1)
|
Reserve additions include proved reserves and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities. We present these metrics separately, both including and excluding the impact of price revisions on reserves, to demonstrate the effectiveness of our drilling program exclusive of economic factors (such as price) outside of our control. All amounts are derived directly from the table presented in “Financial Statements and Supplementary Data—Supplemental Oil and Natural Gas Operations.”
|
(2)
|
Total oil and natural gas capital costs include the costs of development, exploration and property acquisition activities conducted to add reserves and exclude asset retirement obligations. Amounts are derived directly from the table presented in “Financial Statements and Supplementary Data—Supplemental Oil and Natural Gas Operations”. We do not include estimated future capital costs for the development of proved undeveloped reserves in our calculation of reserve replacement costs. See “Business—Oil and Natural Gas Properties—Oil, Natural Gas and NGLs Reserves and Production—Proved Undeveloped Reserves (PUDs)” for the estimated amounts in our
December 31, 2015
internal reserve report to be spent in 2016, 2017 and 2018 to develop our proved undeveloped reserves.
|
|
Including Price Revisions
(1)
|
|
Excluding Price Revisions
(1)
|
||||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
Reserve Replacement Ratios
(2)(3)
|
(117
|
)%
|
|
343
|
%
|
|
476
|
%
|
|
(48
|
)%
|
|
254
|
%
|
|
464
|
%
|
||||||
Proved Developed Reserves
(4)
|
47
|
%
|
|
38
|
%
|
|
33
|
%
|
|
47
|
%
|
|
38
|
%
|
|
33
|
%
|
||||||
Proved Undeveloped Reserves
(4)
|
53
|
%
|
|
62
|
%
|
|
67
|
%
|
|
53
|
%
|
|
62
|
%
|
|
67
|
%
|
||||||
Reserve Replacement Costs
(2)(3)(5)
($/Boe)
|
$
|
(25.78
|
)
|
|
$
|
16.93
|
|
|
$
|
12.62
|
|
|
$
|
(62.52
|
)
|
|
$
|
22.85
|
|
|
$
|
12.95
|
|
|
(2)
|
For the year ended
December 31, 2015
, reserve replacement ratio and reserve replacement costs including acquisitions and price revisions were (90)% and $(36.42) per Boe, and excluding price revisions were (22)% and $(151.77) per Boe. For the year ended
December 31, 2014
, reserve replacement ratio and reserve replacement costs including acquisitions and price revisions were 363% and $16.90 per Boe, and excluding price revisions were 274% and $22.37 per Boe. No acquisitions are included in our reserve replacement ratio or reserve replacement costs for the year ended December 31,
2013
, as any such amounts are immaterial to the amounts presented.
|
(3)
|
For the year ended
December 31, 2015
, reserve replacement ratio and reserve replacement costs were negative due to the impact of the SEC's five-year development rule after reductions in estimated capital in our long-range development plan based on the lower price environment which resulted in negative PUD revisions of 85 MMBoe. The year ended December 31, 2014, includes negative PUD revisions of 2 MMBoe due to long-range development plan reductions resulting from changes in economic outlook.
|
|
2015
|
|
2014
|
|
2013
|
||||||
Reserve Replacement Ratios
(1)
|
164
|
%
|
|
254
|
%
|
|
464
|
%
|
|||
Reserve Replacement Costs
(1)(2)
($/Boe)
|
$
|
18.32
|
|
|
$
|
22.85
|
|
|
$
|
12.95
|
|
|
(1)
|
For the year ended
December 31, 2015
, reserve replacement ratio and reserve replacement costs including acquisitions were 191% and $17.23 per Boe. For the year ended
December 31, 2014
, reserve replacement ratio and reserve replacement costs including acquisitions were 274% and $22.37 per Boe. No acquisitions are included in our reserve replacement ratio or reserve replacement costs for the year ended December 31,
2013
, as any such amounts are immaterial to the amounts presented.
|
(2)
|
Proved and unproved leasehold costs are included in all calculations.
|
|
Year ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
(in millions)
|
|
|
||||||
Operating revenues:
|
|
|
|
|
|
|
|
|
|||
Oil
|
$
|
981
|
|
|
$
|
1,705
|
|
|
$
|
1,254
|
|
Natural gas
|
200
|
|
|
284
|
|
|
300
|
|
|||
NGLs
|
60
|
|
|
110
|
|
|
74
|
|
|||
Total physical sales
|
1,241
|
|
|
2,099
|
|
|
1,628
|
|
|||
Financial derivatives
|
667
|
|
|
985
|
|
|
(52
|
)
|
|||
Total operating revenues
|
1,908
|
|
|
3,084
|
|
|
1,576
|
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
||||
Oil and natural gas purchases
|
31
|
|
|
23
|
|
|
25
|
|
|||
Transportation costs
|
116
|
|
|
100
|
|
|
85
|
|
|||
Lease operating expenses
|
186
|
|
|
193
|
|
|
147
|
|
|||
General and administrative
|
148
|
|
|
244
|
|
|
229
|
|
|||
Depreciation, depletion and amortization
|
983
|
|
|
875
|
|
|
585
|
|
|||
Impairment charges
|
4,299
|
|
|
2
|
|
|
2
|
|
|||
Exploration and other expense
|
20
|
|
|
25
|
|
|
41
|
|
|||
Taxes, other than income taxes
|
80
|
|
|
129
|
|
|
79
|
|
|||
Total operating expenses
|
5,863
|
|
|
1,591
|
|
|
1,193
|
|
|||
Operating (loss) income
|
(3,955
|
)
|
|
1,493
|
|
|
383
|
|
|||
Other income (expense)
|
—
|
|
|
1
|
|
|
(12
|
)
|
|||
Loss on extinguishment of debt
|
(41
|
)
|
|
(17
|
)
|
|
(9
|
)
|
|||
Interest expense
|
(330
|
)
|
|
(318
|
)
|
|
(354
|
)
|
|||
(Loss) income from continuing operations before income taxes
|
(4,326
|
)
|
|
1,159
|
|
|
8
|
|
|||
Income tax (benefit) expense
|
(578
|
)
|
|
432
|
|
|
64
|
|
|||
(Loss) income from continuing operations
|
(3,748
|
)
|
|
727
|
|
|
(56
|
)
|
|||
Income from discontinued operations, net of tax
|
—
|
|
|
4
|
|
|
506
|
|
|||
Net (loss) income
|
$
|
(3,748
|
)
|
|
$
|
731
|
|
|
$
|
450
|
|
|
Year ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
|
(in millions)
|
|
|
|||||
Operating revenues:
|
|
|
|
|
|
|
|
|
|||
Oil
|
$
|
981
|
|
|
$
|
1,705
|
|
|
$
|
1,254
|
|
Natural gas
|
200
|
|
|
284
|
|
|
300
|
|
|||
NGLs
|
60
|
|
|
110
|
|
|
74
|
|
|||
Total physical sales
|
1,241
|
|
|
2,099
|
|
|
1,628
|
|
|||
Financial derivatives
|
667
|
|
|
985
|
|
|
(52
|
)
|
|||
Total operating revenues
|
$
|
1,908
|
|
|
$
|
3,084
|
|
|
$
|
1,576
|
|
Volumes:
|
|
|
|
|
|
|
|
|
|||
Oil (MBbls)
(1)
|
22,078
|
|
|
19,985
|
|
|
13,432
|
|
|||
Natural gas (MMcf)
(1)
|
75,533
|
|
|
69,434
|
|
|
93,866
|
|
|||
NGLs (MBbls)
(1)
|
5,366
|
|
|
4,116
|
|
|
2,761
|
|
|||
Equivalent volumes (MBoe)
(1)
|
40,033
|
|
|
35,673
|
|
|
31,837
|
|
|||
Total MBoe/d
(1)
|
109.7
|
|
|
97.7
|
|
|
87.2
|
|
|||
|
|
|
|
|
|
||||||
Consolidated prices per unit
(2)
:
|
|
|
|
|
|
|
|
|
|||
Oil
|
|
|
|
|
|
|
|
|
|||
Average realized price on physical sales ($/Bbl)
(3)
|
$
|
44.28
|
|
|
$
|
85.31
|
|
|
$
|
94.75
|
|
Average realized price, including financial derivatives ($/Bbl)
(3)(4)
|
$
|
82.18
|
|
|
$
|
88.77
|
|
|
$
|
97.56
|
|
Natural gas
|
|
|
|
|
|
|
|
||||
Average realized price on physical sales ($/Mcf)
(3)
|
$
|
2.27
|
|
|
$
|
3.76
|
|
|
$
|
3.28
|
|
Average realized price, including financial derivatives ($/Mcf)
(3)(4)
|
$
|
3.59
|
|
|
$
|
3.34
|
|
|
$
|
2.97
|
|
NGLs
|
|
|
|
|
|
|
|
|
|||
Average realized price on physical sales ($/Bbl)
|
$
|
11.22
|
|
|
$
|
26.73
|
|
|
$
|
30.58
|
|
Average realized price, including financial derivatives ($/Bbl)
(4)
|
$
|
12.36
|
|
|
$
|
27.78
|
|
|
$
|
—
|
|
|
(1)
|
In September 2013, we sold our equity investment in Four Star. For the year ended December 31, 2013, Four Star’s production volumes were 197 MBbls of oil; 10,050 MMcf of natural gas; 327 MBbls of NGLs; and 2,199 MBoe (6 MBoe/d) of equivalent volumes.
|
(2)
|
Oil prices for the year ended
December 31, 2015
are calculated including a reduction of $3 million for oil purchases associated with managing our physical sales. Natural gas prices for the years ended
December 31, 2015
,
2014
and
2013
are calculated including a reduction of $28 million,
$23 million
and
$25 million
, respectively, for natural gas purchases associated with managing our physical sales. Prices per unit are based on consolidated volumes and do not include volumes associated with Four Star which was sold in September 2013.
|
(3)
|
Changes in realized oil and natural gas prices reflect the effects of unfavorable unhedged locational or basis differentials, unhedged volumes and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.
|
(4)
|
The years ended
December 31, 2015
,
2014
and 2013 include approximately $837 million, $69 million and $29 million, respectively, of cash receipts for the settlement of crude oil derivative contracts. The years ended
December 31, 2015
,
2014
and
2013
include approximately $99 million of cash received, $30 million of cash paid and $28 million of cash paid for the settlement of natural gas financial derivatives. For the years ended
December 31, 2015
and
2014
, we received approximately $6 million and $4 million, respectively, for the settlement of NGLs derivative contracts. No cash premiums were received or paid for the year ended
December 31, 2015
. Cash premiums received for the years ended December 31,
2014
and 2013, were approximately $1 million and $9 million, respectively.
|
|
Oil
|
|
Natural gas
|
|
NGLs
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
December 31, 2014 sales
|
$
|
1,705
|
|
|
$
|
284
|
|
|
$
|
110
|
|
|
$
|
2,099
|
|
Change due to prices
|
(903
|
)
|
|
(109
|
)
|
|
(83
|
)
|
|
(1,095
|
)
|
||||
Change due to volumes
|
179
|
|
|
25
|
|
|
33
|
|
|
237
|
|
||||
December 31, 2015 sales
|
$
|
981
|
|
|
$
|
200
|
|
|
$
|
60
|
|
|
$
|
1,241
|
|
|
Years ended December 31,
|
||||||||||||||
|
2015
|
|
2014
|
||||||||||||
|
Oil
(Bbl)
|
|
Natural gas
(MMBtu)
|
|
Oil
(Bbl)
|
|
Natural gas
(MMBtu)
|
||||||||
Differentials and deducts
|
$
|
(4.91
|
)
|
|
$
|
(0.40
|
)
|
|
$
|
(7.69
|
)
|
|
$
|
(0.60
|
)
|
NYMEX
|
$
|
48.80
|
|
|
$
|
2.67
|
|
|
$
|
92.99
|
|
|
$
|
4.41
|
|
|
Year ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Depreciation, depletion and amortization ($/Boe)
|
$
|
24.54
|
|
|
$
|
24.53
|
|
|
$
|
19.74
|
|
|
Year ended December 31,
|
||||||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||||||||||||||
|
Total
|
|
Per Unit
(1)
|
|
Total
|
|
Per Unit
(1)
|
|
Total
|
|
Per Unit
(1)
|
||||||||||||
|
(in millions, except per unit costs)
|
||||||||||||||||||||||
Total continuing operating expenses
|
$
|
5,863
|
|
|
$
|
146.44
|
|
|
$
|
1,591
|
|
|
$
|
44.59
|
|
|
$
|
1,193
|
|
|
$
|
40.26
|
|
Depreciation, depletion and amortization
|
(983
|
)
|
|
(24.54
|
)
|
|
(875
|
)
|
|
(24.53
|
)
|
|
(585
|
)
|
|
(19.74
|
)
|
||||||
Transportation costs
|
(116
|
)
|
|
(2.88
|
)
|
|
(100
|
)
|
|
(2.81
|
)
|
|
(85
|
)
|
|
(2.85
|
)
|
||||||
Exploration expense
|
(18
|
)
|
|
(0.44
|
)
|
|
(22
|
)
|
|
(0.62
|
)
|
|
(41
|
)
|
|
(1.39
|
)
|
||||||
Oil and natural gas purchases
|
(31
|
)
|
|
(0.79
|
)
|
|
(23
|
)
|
|
(0.64
|
)
|
|
(25
|
)
|
|
(0.85
|
)
|
||||||
Impairment charges
|
(4,299
|
)
|
|
(107.38
|
)
|
|
(2
|
)
|
|
(0.05
|
)
|
|
(2
|
)
|
|
(0.06
|
)
|
||||||
Total continuing cash operating costs
|
416
|
|
|
10.41
|
|
|
569
|
|
|
15.94
|
|
|
455
|
|
|
15.37
|
|
||||||
Transition/restructuring costs, non-cash portion of compensation expense and other
(2)
|
(21
|
)
|
|
(0.52
|
)
|
|
(95
|
)
|
|
(2.67
|
)
|
|
(65
|
)
|
|
(2.19
|
)
|
||||||
Total adjusted cash operating costs and adjusted per-unit cash costs
(3)
|
$
|
395
|
|
|
$
|
9.89
|
|
|
$
|
474
|
|
|
$
|
13.27
|
|
|
$
|
390
|
|
|
$
|
13.18
|
|
Total equivalent volumes (MBoe)
(3)
|
40,033
|
|
|
|
|
35,673
|
|
|
|
|
|
29,638
|
|
|
|
|
|
(2)
|
For the year ended
December 31, 2015
, amount includes approximately
$8 million
of transition and severance costs related to restructuring and
$13 million
of non-cash compensation expense, adjusted for cash payments made on long-term incentive plans of approximately
$8 million
. For the year ended December 31, 2014, amount includes
$90 million
of transaction, management and other fees paid to our Sponsors,
$11 million
of cash received from an insurance settlement,
$5 million
of acquisition costs, $9 million of non-cash compensation expense and $2 million of transition and severance costs related to restructuring. For the year ended December 31, 2013, amount includes $7 million of transition and severance costs associated with asset divestitures, management and other fees paid to our Sponsors of $26 million, $31 million of non-cash compensation expense and $1 million of costs associated with our initial public offering. The non-cash portion of compensation expense represents non-cash compensation expense under our long-term incentive programs adjusted for cash payments made under our long-term incentive plans.
|
|
Year ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Average cash operating costs ($/Boe)
|
|
|
|
|
|
|
|
|
|||
Lease operating expenses
|
$
|
4.64
|
|
|
$
|
5.40
|
|
|
$
|
4.98
|
|
Production taxes
(1)
|
1.83
|
|
|
3.39
|
|
|
2.84
|
|
|||
General and administrative expenses
(2)
|
3.71
|
|
|
6.83
|
|
|
7.73
|
|
|||
Taxes, other than production and income taxes
(3)
|
0.17
|
|
|
0.23
|
|
|
(0.18
|
)
|
|||
Other expense
(4)
|
0.06
|
|
|
0.09
|
|
|
—
|
|
|||
Total continuing cash operating costs
|
10.41
|
|
|
15.94
|
|
|
15.37
|
|
|||
Transition/restructuring costs, non-cash portion of compensation expense and other
(2)
|
(0.52
|
)
|
|
(2.67
|
)
|
|
(2.19
|
)
|
|||
Total adjusted cash operating costs
|
$
|
9.89
|
|
|
$
|
13.27
|
|
|
$
|
13.18
|
|
|
(1)
|
Production taxes include ad valorem and severance taxes which decreased in 2015 due primarily to lower commodity prices and increased in 2014 primarily due to higher severance taxes associated with our higher oil production.
|
(2)
|
For additional detail of adjusted items included in general and administrative expenses, refer to the reconciliation of cash operating costs and adjusted cash operating costs above.
|
|
Year ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Net (loss) income
|
$
|
(3,748
|
)
|
|
$
|
731
|
|
|
$
|
450
|
|
Income from discontinued operations, net of tax
|
—
|
|
|
(4
|
)
|
|
(506
|
)
|
|||
(Loss) income from continuing operations
|
(3,748
|
)
|
|
727
|
|
|
(56
|
)
|
|||
Income tax (benefit) expense
|
(578
|
)
|
|
432
|
|
|
64
|
|
|||
Interest expense, net of capitalized interest
|
330
|
|
|
318
|
|
|
354
|
|
|||
Depreciation, depletion and amortization
|
983
|
|
|
875
|
|
|
585
|
|
|||
Exploration expense
|
18
|
|
|
22
|
|
|
41
|
|
|||
EBITDAX
|
(2,995
|
)
|
|
2,374
|
|
|
988
|
|
|||
Mark-to-market on financial derivatives
(1)
|
(667
|
)
|
|
(985
|
)
|
|
52
|
|
|||
Settlements and cash premiums on financial derivatives
(2)
|
942
|
|
|
44
|
|
|
10
|
|
|||
Non-cash portion of compensation expense
(3)
|
13
|
|
|
9
|
|
|
31
|
|
|||
Transition, restructuring and other costs
(4)
|
8
|
|
|
(4
|
)
|
|
8
|
|
|||
Fees paid to Sponsors
(5)
|
—
|
|
|
90
|
|
|
26
|
|
|||
Loss on extinguishment of debt
(6)
|
41
|
|
|
17
|
|
|
9
|
|
|||
Loss from unconsolidated affiliate
(7)
|
—
|
|
|
—
|
|
|
13
|
|
|||
Impairment charges
|
4,299
|
|
|
2
|
|
|
2
|
|
|||
Adjusted EBITDAX
|
$
|
1,641
|
|
|
$
|
1,547
|
|
|
$
|
1,139
|
|
|
(2)
|
Represents actual settlements related to financial derivatives, including cash premiums. No cash premiums were received or paid for the year ended
December 31, 2015
. For the years ended
December 31, 2014
and
2013
, we received approximately $1 million and $9 million of cash premiums, respectively.
|
(4)
|
Reflects transition and severance costs related to restructuring for the year ended December 31, 2015. Reflects an $11 million insurance settlement and $5 million of acquisition costs as well as transition and severance costs related to restructuring or asset sales in 2015, 2014 and 2013 and costs incurred related to our initial public offering in 2013.
|
(6)
|
Represents the loss on extinguishment of debt recorded related to the repayment in May 2015 of our 2019 $750 million senior secured note for the year ended
December 31, 2015
. Represents the loss on extinguishment of debt recorded related to the retirement of the PIK toggle note in 2014, the redetermination of the RBL Facility and a partial repayment of the term loan in 2013.
|
(7)
|
Reflects the elimination of equity income (losses) recognized from Four Star, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets, as a result of the sale of Four Star in September 2013.
|
|
Capital
Expenditures
(1)
(in millions)
|
|
Average Drilling
Rigs
|
|||
Eagle Ford Shale
(2)
|
$
|
855
|
|
|
3.7
|
|
Wolfcamp Shale
|
249
|
|
|
1.2
|
|
|
Altamont
|
158
|
|
|
1.5
|
|
|
Haynesville Shale
|
60
|
|
|
0.4
|
|
|
Other
|
2
|
|
|
—
|
|
|
Total
|
$
|
1,324
|
|
|
6.8
|
|
|
|
Year ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
(in millions)
|
|
|
||||||
Cash Flow from Operations
|
|
|
|
|
|
|
|
|
|||
Operating activities
|
|
|
|
|
|
|
|
|
|||
Net (loss) income
|
$
|
(3,748
|
)
|
|
$
|
731
|
|
|
$
|
450
|
|
Impairment charges
|
4,299
|
|
|
20
|
|
|
46
|
|
|||
Gain on sale of assets
|
—
|
|
|
(2
|
)
|
|
(468
|
)
|
|||
Other income adjustments
|
497
|
|
|
1,390
|
|
|
863
|
|
|||
Change in assets and liabilities
|
279
|
|
|
(953
|
)
|
|
69
|
|
|||
Total cash flow from operations
|
$
|
1,327
|
|
|
$
|
1,186
|
|
|
$
|
960
|
|
|
|
|
|
|
|
||||||
Other Cash Inflows
|
|
|
|
|
|
|
|
|
|||
Investing activities
|
|
|
|
|
|
|
|
|
|||
Proceeds from the sale of assets and investments, net of cash transferred
|
$
|
1
|
|
|
$
|
154
|
|
|
$
|
1,451
|
|
|
|
|
|
|
|
||||||
Financing activities
|
|
|
|
|
|
|
|
||||
Proceeds from issuance of long-term debt
|
2,067
|
|
|
2,455
|
|
|
1,880
|
|
|||
Proceeds from issuance of stock
|
—
|
|
|
669
|
|
|
—
|
|
|||
Contributions
|
—
|
|
|
—
|
|
|
17
|
|
|||
|
2,067
|
|
|
3,124
|
|
|
1,897
|
|
|||
Total cash inflows
|
$
|
2,068
|
|
|
$
|
3,278
|
|
|
$
|
3,348
|
|
|
|
|
|
|
|
||||||
Cash Outflows
|
|
|
|
|
|
|
|
||||
Investing activities
|
|
|
|
|
|
|
|
||||
Cash paid for capital expenditures
|
$
|
1,433
|
|
|
$
|
2,033
|
|
|
$
|
1,924
|
|
Cash paid for acquisitions, net of cash acquired
|
111
|
|
|
165
|
|
|
2
|
|
|||
|
$
|
1,544
|
|
|
$
|
2,198
|
|
|
$
|
1,926
|
|
Financing activities
|
|
|
|
|
|
|
|
||||
Repayments of long-term debt
|
1,826
|
|
|
2,293
|
|
|
2,190
|
|
|||
Distributions to members
|
—
|
|
|
—
|
|
|
205
|
|
|||
Debt issuance costs
|
20
|
|
|
1
|
|
|
5
|
|
|||
Other
|
1
|
|
|
1
|
|
|
—
|
|
|||
|
1,847
|
|
|
2,295
|
|
|
2,400
|
|
|||
Total cash outflows
|
$
|
3,391
|
|
|
$
|
4,493
|
|
|
$
|
4,326
|
|
|
|
|
|
|
|
||||||
Net change in cash and cash equivalents
|
$
|
4
|
|
|
$
|
(29
|
)
|
|
$
|
(18
|
)
|
|
2016
|
|
2017- 2018
|
|
2019 - 2020
|
|
Thereafter
|
|
Total
|
||||||||||
|
|
|
|
|
(in millions)
|
|
|
|
|
||||||||||
Long-term financing obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Principal
|
$
|
—
|
|
|
$
|
500
|
|
|
$
|
3,222
|
|
|
$
|
1,150
|
|
|
$
|
4,872
|
|
Interest
|
320
|
|
|
630
|
|
|
421
|
|
|
170
|
|
|
1,541
|
|
|||||
Liabilities from derivatives
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Operating leases
|
12
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|||||
Other contractual commitments and purchase obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Volume and transportation commitments
|
82
|
|
|
171
|
|
|
151
|
|
|
109
|
|
|
513
|
|
|||||
Other obligations
|
82
|
|
|
45
|
|
|
1
|
|
|
—
|
|
|
128
|
|
|||||
Total contractual obligations
|
$
|
496
|
|
|
$
|
1,376
|
|
|
$
|
3,795
|
|
|
$
|
1,429
|
|
|
$
|
7,096
|
|
•
|
Volume and Transportation Commitments.
Included in these amounts are commitments for volume deficiency contracts and demand charges for firm access to natural gas transportation as well as firm oil capacity.
|
•
|
Other Obligations.
Included in these amounts are commitments for drilling, completions and seismic activities for our operations and various other maintenance, engineering, procurement and construction contracts. Our future commitments under these contracts may change reflecting changes in commodity prices and any related effect on the supply/demand for these services. We have excluded asset retirement obligations and reserves for litigation and environmental remediation, as these liabilities are not contractually fixed as to timing and amount.
|
|
|
|
Change in Price
|
||||||||||||||||
|
|
|
10 Percent Increase
|
|
10 Percent Decrease
|
||||||||||||||
|
Fair Value
|
|
Fair Value
|
|
Change
|
|
Fair Value
|
|
Change
|
||||||||||
|
|
|
|
|
(in millions)
|
|
|
|
|
||||||||||
Commodity-based derivatives—net assets (liabilities)
|
$
|
770
|
|
|
$
|
676
|
|
|
$
|
(94
|
)
|
|
$
|
864
|
|
|
$
|
94
|
|
•
|
changes in oil, natural gas and NGLs prices impact the amounts at which we sell our production and affect the fair value of our oil and natural gas derivative contracts; and
|
•
|
changes in locational price differences also affect amounts at which we sell our oil, natural gas and NGLs production, and the fair values of any related derivative products.
|
•
|
changes in interest rates affect the interest expense we incur on our variable-rate debt and the fair value of fixed-rate debt;
|
•
|
changes in interest rates result in increases or decreases in the unrealized value of our derivative positions; and
|
•
|
changes in interest rates used to discount liabilities result in higher or lower accretion expense over time.
|
•
|
forward contracts, which commit us to purchase or sell energy commodities in the future;
|
•
|
option contracts, which convey the right to buy or sell a commodity, financial instrument or index at a predetermined price;
|
•
|
swap contracts, which require payments to or from counterparties based upon the differential between two prices or rates for a predetermined contractual (notional) quantity; and
|
•
|
structured contracts, which may involve a variety of the above characteristics.
|
|
|
|
Oil, Natural Gas and NGLs Derivatives
|
||||||||||||||||
|
|
|
1 Percent Increase
|
|
1 Percent Decrease
|
||||||||||||||
|
Fair Value
|
|
Fair Value
|
|
Change
|
|
Fair Value
|
|
Change
|
||||||||||
|
|
|
|
|
(in millions)
|
|
|
|
|
||||||||||
Discount Rate
(2)
|
$
|
770
|
|
|
$
|
765
|
|
|
$
|
(5
|
)
|
|
$
|
775
|
|
|
$
|
5
|
|
Credit rate
(3)
|
$
|
770
|
|
|
$
|
762
|
|
|
$
|
(8
|
)
|
|
$
|
774
|
|
|
$
|
4
|
|
|
|
December 31, 2015
|
|
December 31, 2014
|
||||||||||||||||||||||||||||||||||||
|
Expected Fiscal Year of Maturity of Carrying Amounts
|
|
|
|
Fair Value
|
|
Carrying Amounts
|
|
Fair Value
|
||||||||||||||||||||||||||||||
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Total
|
|
|
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||
Fixed rate long-term debt
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,000
|
|
|
$
|
1,150
|
|
|
$
|
3,150
|
|
|
$
|
1,797
|
|
|
$
|
3,100
|
|
|
$
|
3,111
|
|
Average interest rate
|
8.4
|
%
|
|
8.4
|
%
|
|
8.4
|
%
|
|
8.4
|
%
|
|
7.7
|
%
|
|
6.6
|
%
|
|
|
|
|
|
|
|
|
||||||||||||||
Variable rate long-term debt
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
497
|
|
|
$
|
1,222
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,719
|
|
|
$
|
1,582
|
|
|
$
|
1,498
|
|
|
$
|
1,471
|
|
Average interest rate
|
3.2
|
%
|
|
3.2
|
%
|
|
3.1
|
%
|
|
3.0
|
%
|
|
—
|
%
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|
Page
|
|
|
Supplemental Financial Information
|
|
|
|
Schedules
|
|
•
|
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
|
•
|
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
|
•
|
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
|
|
/s/ Ernst & Young LLP
|
|
|
Houston, Texas
|
|
February 19, 2016
|
|
|
/s/ Ernst & Young LLP
|
|
|
Houston, Texas
|
|
February 19, 2016
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Operating revenues
|
|
|
|
|
|
|
|
|
|||
Oil
|
$
|
981
|
|
|
$
|
1,705
|
|
|
$
|
1,254
|
|
Natural gas
|
200
|
|
|
284
|
|
|
300
|
|
|||
NGLs
|
60
|
|
|
110
|
|
|
74
|
|
|||
Financial derivatives
|
667
|
|
|
985
|
|
|
(52
|
)
|
|||
Total operating revenues
|
1,908
|
|
|
3,084
|
|
|
1,576
|
|
|||
|
|
|
|
|
|
||||||
Operating expenses
|
|
|
|
|
|
|
|
|
|||
Oil and natural gas purchases
|
31
|
|
|
23
|
|
|
25
|
|
|||
Transportation costs
|
116
|
|
|
100
|
|
|
85
|
|
|||
Lease operating expense
|
186
|
|
|
193
|
|
|
147
|
|
|||
General and administrative
|
148
|
|
|
244
|
|
|
229
|
|
|||
Depreciation, depletion and amortization
|
983
|
|
|
875
|
|
|
585
|
|
|||
Impairment charges
|
4,299
|
|
|
2
|
|
|
2
|
|
|||
Exploration and other expense
|
20
|
|
|
25
|
|
|
41
|
|
|||
Taxes, other than income taxes
|
80
|
|
|
129
|
|
|
79
|
|
|||
Total operating expenses
|
5,863
|
|
|
1,591
|
|
|
1,193
|
|
|||
|
|
|
|
|
|
||||||
Operating (loss) income
|
(3,955
|
)
|
|
1,493
|
|
|
383
|
|
|||
Other income (expense)
|
—
|
|
|
1
|
|
|
(12
|
)
|
|||
Loss on extinguishment of debt
|
(41
|
)
|
|
(17
|
)
|
|
(9
|
)
|
|||
Interest expense
|
(330
|
)
|
|
(318
|
)
|
|
(354
|
)
|
|||
(Loss) income from continuing operations before income taxes
|
(4,326
|
)
|
|
1,159
|
|
|
8
|
|
|||
Income tax (benefit) expense
|
(578
|
)
|
|
432
|
|
|
64
|
|
|||
(Loss) income from continuing operations
|
(3,748
|
)
|
|
727
|
|
|
(56
|
)
|
|||
Income from discontinued operations, net of tax
|
—
|
|
|
4
|
|
|
506
|
|
|||
Net (loss) income
|
$
|
(3,748
|
)
|
|
$
|
731
|
|
|
$
|
450
|
|
|
|
|
|
|
|
||||||
Basic and diluted net income (loss) per common share
|
|
|
|
|
|
|
|
|
|||
(Loss) income from continuing operations
|
$
|
(15.37
|
)
|
|
$
|
3.00
|
|
|
$
|
(0.27
|
)
|
Income from discontinued operations, net of tax
|
—
|
|
|
0.02
|
|
|
2.43
|
|
|||
Net (loss) income
|
$
|
(15.37
|
)
|
|
$
|
3.02
|
|
|
$
|
2.16
|
|
Basic and diluted weighted average common shares outstanding
|
244
|
|
|
242
|
|
|
209
|
|
|
December 31, 2015
|
|
December 31, 2014
|
||||
ASSETS
|
|
|
|
|
|
||
Current assets
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
26
|
|
|
$
|
22
|
|
Accounts receivable
|
|
|
|
|
|
||
Customer, net of allowance of $1 in 2015 and less than $1 in 2014
|
202
|
|
|
234
|
|
||
Other, net of allowance of $1 for 2015 and 2014
|
15
|
|
|
38
|
|
||
Income tax receivable
|
3
|
|
|
24
|
|
||
Materials and supplies
|
24
|
|
|
25
|
|
||
Derivative instruments
|
694
|
|
|
752
|
|
||
Prepaid assets
|
5
|
|
|
7
|
|
||
Total current assets
|
969
|
|
|
1,102
|
|
||
Property, plant and equipment, at cost
|
|
|
|
|
|
||
Oil and natural gas properties
|
7,228
|
|
|
10,241
|
|
||
Other property, plant and equipment
|
82
|
|
|
76
|
|
||
|
7,310
|
|
|
10,317
|
|
||
Less accumulated depreciation, depletion and amortization
|
2,555
|
|
|
1,589
|
|
||
Total property, plant and equipment, net
|
4,755
|
|
|
8,728
|
|
||
Other assets
|
|
|
|
|
|
||
Derivative instruments
|
85
|
|
|
297
|
|
||
Unamortized debt issue costs - revolving credit facility
|
23
|
|
|
25
|
|
||
Other
|
1
|
|
|
2
|
|
||
|
109
|
|
|
324
|
|
||
Total assets
|
$
|
5,833
|
|
|
$
|
10,154
|
|
|
December 31, 2015
|
|
December 31, 2014
|
||||
LIABILITIES AND EQUITY
|
|
|
|
|
|
||
Current liabilities
|
|
|
|
|
|
||
Accounts payable
|
|
|
|
|
|
||
Trade
|
$
|
79
|
|
|
$
|
142
|
|
Other
|
171
|
|
|
403
|
|
||
Derivative instruments
|
—
|
|
|
1
|
|
||
Accrued interest
|
47
|
|
|
53
|
|
||
Asset retirement obligations
|
1
|
|
|
2
|
|
||
Other accrued liabilities
|
50
|
|
|
47
|
|
||
Total current liabilities
|
348
|
|
|
648
|
|
||
|
|
|
|
||||
Long-term debt
|
4,812
|
|
|
4,533
|
|
||
Other long-term liabilities
|
|
|
|
|
|
||
Deferred income taxes
|
—
|
|
|
578
|
|
||
Derivative instruments
|
8
|
|
|
—
|
|
||
Asset retirement obligations
|
40
|
|
|
40
|
|
||
Other
|
6
|
|
|
7
|
|
||
Total non-current liabilities
|
4,866
|
|
|
5,158
|
|
||
|
|
|
|
||||
Commitments and contingencies (Note 9)
|
|
|
|
|
|
||
|
|
|
|
||||
Stockholders’ equity
|
|
|
|
|
|
||
Class A shares, $0.01 par value; 550 million shares authorized; 248 million shares issued and outstanding at December 31, 2015; 245 million shares issued and outstanding at December 31, 2014
|
2
|
|
|
2
|
|
||
Class B shares, $0.01 par value; 0.8 million shares authorized, issued and outstanding at December 31, 2015 and December 31, 2014
|
—
|
|
|
—
|
|
||
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding
|
—
|
|
|
—
|
|
||
Additional paid-in capital
|
3,529
|
|
|
3,510
|
|
||
(Accumulated deficit) Retained earnings
|
(2,912
|
)
|
|
836
|
|
||
Total stockholders’ equity
|
619
|
|
|
4,348
|
|
||
Total liabilities and equity
|
$
|
5,833
|
|
|
$
|
10,154
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|||
Net (loss) income
|
$
|
(3,748
|
)
|
|
$
|
731
|
|
|
$
|
450
|
|
Adjustments to reconcile net (loss) income to net cash provided by operating activities
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization
|
983
|
|
|
883
|
|
|
666
|
|
|||
Gain on sale of assets
|
—
|
|
|
(2
|
)
|
|
(468
|
)
|
|||
Deferred income tax (benefit) expense
|
(578
|
)
|
|
435
|
|
|
67
|
|
|||
Loss from unconsolidated affiliate, net of cash distributions
|
—
|
|
|
—
|
|
|
37
|
|
|||
Impairment charges
|
4,299
|
|
|
20
|
|
|
46
|
|
|||
Loss on extinguishment of debt
|
41
|
|
|
17
|
|
|
9
|
|
|||
Share-based compensation expense
|
19
|
|
|
13
|
|
|
22
|
|
|||
Non-cash portion of exploration expense
|
14
|
|
|
19
|
|
|
39
|
|
|||
Amortization of debt issuance costs
|
18
|
|
|
21
|
|
|
22
|
|
|||
Other
|
—
|
|
|
2
|
|
|
1
|
|
|||
Asset and liability changes
|
|
|
|
|
|
|
|
|
|||
Accounts receivable
|
55
|
|
|
7
|
|
|
(50
|
)
|
|||
Accounts payable
|
(70
|
)
|
|
13
|
|
|
80
|
|
|||
Derivative instruments
|
277
|
|
|
(939
|
)
|
|
56
|
|
|||
Accrued interest
|
(6
|
)
|
|
—
|
|
|
(3
|
)
|
|||
Other asset changes
|
22
|
|
|
5
|
|
|
(13
|
)
|
|||
Other liability changes
|
1
|
|
|
(39
|
)
|
|
(1
|
)
|
|||
Net cash provided by operating activities
|
1,327
|
|
|
1,186
|
|
|
960
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|||
Cash paid for capital expenditures
|
(1,433
|
)
|
|
(2,033
|
)
|
|
(1,924
|
)
|
|||
Proceeds from the sale of assets and investments, net of cash transferred
|
1
|
|
|
154
|
|
|
1,451
|
|
|||
Cash paid for acquisitions, net of cash acquired
|
(111
|
)
|
|
(165
|
)
|
|
(2
|
)
|
|||
Net cash used in investing activities
|
(1,543
|
)
|
|
(2,044
|
)
|
|
(475
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|||
Proceeds from issuance of long-term debt
|
2,067
|
|
|
2,455
|
|
|
1,880
|
|
|||
Repayments of long-term debt
|
(1,826
|
)
|
|
(2,293
|
)
|
|
(2,190
|
)
|
|||
Proceeds from issuance of stock
|
—
|
|
|
669
|
|
|
—
|
|
|||
Distributions to members
|
—
|
|
|
—
|
|
|
(205
|
)
|
|||
Contributions from members
|
—
|
|
|
—
|
|
|
17
|
|
|||
Debt issuance costs
|
(20
|
)
|
|
(1
|
)
|
|
(5
|
)
|
|||
Other
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
220
|
|
|
829
|
|
|
(503
|
)
|
|||
|
|
|
|
|
|
||||||
Change in cash and cash equivalents
|
4
|
|
|
(29
|
)
|
|
(18
|
)
|
|||
Cash and cash equivalents
|
|
|
|
|
|
|
|
|
|||
Beginning of period
|
22
|
|
|
51
|
|
|
69
|
|
|||
End of period
|
$
|
26
|
|
|
$
|
22
|
|
|
$
|
51
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
|||
Interest paid, net of amounts capitalized
|
$
|
312
|
|
|
$
|
289
|
|
|
$
|
305
|
|
Income tax (refunds) payments net of refunds
|
(22
|
)
|
|
26
|
|
|
16
|
|
|
Stockholders’ Equity
|
||||||||||||||||||||||||||||
|
Class A Stock
|
|
Class B Stock
|
|
Additional
Paid-in
Capital
|
|
Retained
Earnings
(Accumulated
Deficit)
|
|
Total
Stockholders’
Equity
|
|
Members’
Equity
|
||||||||||||||||||
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
||||||||||||||||||
Balance at January 1, 2013
|
|
|
|
$
|
—
|
|
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,748
|
|
Share-based compensation
|
|
|
|
—
|
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15
|
|
||||||
Member’s distribution
|
|
|
|
—
|
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(205
|
)
|
||||||
Net income
|
|
|
|
—
|
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
345
|
|
||||||
Corporate reorganization
|
209
|
|
|
—
|
|
|
0.9
|
|
|
—
|
|
|
2,903
|
|
|
—
|
|
|
—
|
|
|
(2,903
|
)
|
||||||
Balance at August 31, 2013 (Corporate Reorganization)
|
209
|
|
|
$
|
—
|
|
|
0.9
|
|
|
$
|
—
|
|
|
$
|
2,903
|
|
|
$
|
—
|
|
|
$
|
2,903
|
|
|
$
|
—
|
|
Income taxes recorded upon corporate reorganization
|
|
|
|
—
|
|
|
|
|
|
—
|
|
|
(78
|
)
|
|
—
|
|
|
(78
|
)
|
|
|
|
||||||
Share-based compensation
|
|
|
|
—
|
|
|
|
|
|
—
|
|
|
7
|
|
|
—
|
|
|
7
|
|
|
|
|
||||||
Net income
|
|
|
|
—
|
|
|
|
|
|
—
|
|
|
—
|
|
|
105
|
|
|
105
|
|
|
|
|
||||||
Balance at December 31, 2013
|
209
|
|
|
$
|
—
|
|
|
0.9
|
|
|
$
|
—
|
|
|
$
|
2,832
|
|
|
$
|
105
|
|
|
$
|
2,937
|
|
|
|
|
|
Share-based compensation
|
1
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
|
|
|
||||||
Initial public offering of common stock
|
35
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
667
|
|
|
—
|
|
|
669
|
|
|
|
|
||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
731
|
|
|
731
|
|
|
|
|
||||||
Balance at December 31, 2014
|
245
|
|
|
$
|
2
|
|
|
0.8
|
|
|
$
|
—
|
|
|
$
|
3,510
|
|
|
$
|
836
|
|
|
$
|
4,348
|
|
|
|
|
|
Share-based compensation
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
19
|
|
|
|
|||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,748
|
)
|
|
(3,748
|
)
|
|
|
|||||||
Balance at December 31, 2015
|
248
|
|
|
$
|
2
|
|
|
0.8
|
|
|
$
|
—
|
|
|
$
|
3,529
|
|
|
$
|
(2,912
|
)
|
|
$
|
619
|
|
|
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in millions)
|
||||||
Operating revenues
|
$
|
82
|
|
|
$
|
361
|
|
|
|
|
|
||||
Operating expenses
|
|
|
|
|
|
||
Natural gas purchases
|
—
|
|
|
19
|
|
||
Transportation costs
|
5
|
|
|
25
|
|
||
Lease operating expense
|
31
|
|
|
92
|
|
||
Depreciation, depletion and amortization
|
8
|
|
|
81
|
|
||
Impairment and ceiling test charges
(1)
|
18
|
|
|
44
|
|
||
Other expense
|
17
|
|
|
53
|
|
||
Total operating expenses
|
79
|
|
|
314
|
|
||
|
|
|
|
||||
Gain on sale of assets
|
2
|
|
|
468
|
|
||
Other income (expense)
|
4
|
|
|
(2
|
)
|
||
Income from discontinued operations before income taxes
|
9
|
|
|
513
|
|
||
Income tax expense
|
5
|
|
|
7
|
|
||
Income from discontinued operations, net of tax
|
$
|
4
|
|
|
$
|
506
|
|
|
(1)
|
During the years ended
December 31, 2014
and 2013, we recorded
$18 million
and
$44 million
, respectively, in impairment charges related to the sale of our Brazilian operations.
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Pretax Income (Loss)
|
|
|
|
|
|
|
|
|
|||
U.S.
|
$
|
(4,326
|
)
|
|
$
|
1,159
|
|
|
$
|
8
|
|
|
|
|
|
|
|
||||||
Components of Income Tax Expense (Benefit)
|
|
|
|
|
|
|
|
|
|||
Current
|
|
|
|
|
|
|
|
|
|||
Federal
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
|
|
|
|
|
||||||
Deferred
|
|
|
|
|
|
|
|
|
|||
Federal
|
(543
|
)
|
|
415
|
|
|
59
|
|
|||
State
|
(35
|
)
|
|
17
|
|
|
7
|
|
|||
|
(578
|
)
|
|
432
|
|
|
66
|
|
|||
Total income tax (benefit) expense
|
$
|
(578
|
)
|
|
$
|
432
|
|
|
$
|
64
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
(in millions)
|
|
|
||||||
Income taxes at the statutory federal rate of 35%
|
$
|
(1,514
|
)
|
|
$
|
406
|
|
|
$
|
3
|
|
Increase (decrease)
|
|
|
|
|
|
|
|
|
|||
State income taxes, net of federal income tax effect
|
(41
|
)
|
|
12
|
|
|
4
|
|
|||
Partnership earnings not subject to tax
|
—
|
|
|
—
|
|
|
57
|
|
|||
Non-deductible reorganization costs
|
—
|
|
|
10
|
|
|
—
|
|
|||
Valuation allowance
|
975
|
|
|
—
|
|
|
—
|
|
|||
Other
|
2
|
|
|
4
|
|
|
—
|
|
|||
Income tax (benefit) expense
|
$
|
(578
|
)
|
|
$
|
432
|
|
|
$
|
64
|
|
|
December 31,
2015 |
|
December 31,
2014 |
||||
|
(in millions)
|
||||||
Deferred tax assets
|
|
|
|
|
|
||
Property, plant and equipment
|
$
|
471
|
|
|
$
|
—
|
|
Net operating loss carryovers
|
720
|
|
|
532
|
|
||
U.S. tax credit carryovers
|
10
|
|
|
10
|
|
||
Employee benefits
|
4
|
|
|
1
|
|
||
Legal and other reserves
|
7
|
|
|
5
|
|
||
Asset retirement obligations
|
19
|
|
|
15
|
|
||
Transaction costs
|
22
|
|
|
21
|
|
||
Total deferred tax assets
|
1,253
|
|
|
584
|
|
||
Valuation allowance
|
(976
|
)
|
|
(1
|
)
|
||
Net deferred tax assets
|
277
|
|
|
583
|
|
||
Deferred tax liabilities
|
|
|
|
|
|
||
Property, plant and equipment
|
—
|
|
|
794
|
|
||
Financial derivatives
|
277
|
|
|
367
|
|
||
Total deferred tax liabilities
|
277
|
|
|
1,161
|
|
||
Net deferred tax liabilities
|
$
|
—
|
|
|
$
|
578
|
|
|
Expiration Period
|
||
|
2031 - 2035
|
||
U.S. federal net operating loss
|
$
|
1,997
|
|
|
2016 - 2035
|
||
State net operating loss
|
$
|
315
|
|
•
|
Level 1 instruments’ fair values are based on quoted prices in actively traded markets.
|
•
|
Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets).
|
•
|
Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 instruments, but also reflect adjustments for being in less liquid markets or having longer contractual terms.
|
|
December 31, 2015
|
|
December 31, 2014
|
||||||||||||
|
Carrying
Amount
|
|
Fair Value
|
|
Carrying
Amount
|
|
Fair Value
|
||||||||
|
(in millions)
|
||||||||||||||
Long-term debt
|
$
|
4,869
|
|
|
$
|
3,379
|
|
|
$
|
4,598
|
|
|
$
|
4,582
|
|
|
|
|
|
|
|
|
|
||||||||
Derivative instruments
|
$
|
771
|
|
|
$
|
771
|
|
|
$
|
1,048
|
|
|
$
|
1,048
|
|
|
Level 2
|
||||||||||||||||||||||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||||||||||||||||||
|
Gross
Fair Value
|
|
|
|
Balance Sheet Location
|
|
Gross
Fair Value
|
|
|
|
Balance Sheet Location
|
||||||||||||||||||||
|
|
Impact of
Netting
|
|
Current
|
|
Non-current
|
|
|
Impact of
Netting
|
|
Current
|
|
Non-current
|
||||||||||||||||||
|
|
|
(in millions)
|
|
|
|
|
|
(in millions)
|
|
|
||||||||||||||||||||
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Derivative instruments
|
$
|
795
|
|
|
$
|
(16
|
)
|
|
$
|
694
|
|
|
$
|
85
|
|
|
$
|
(24
|
)
|
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Derivative instruments
|
$
|
1,093
|
|
|
$
|
(44
|
)
|
|
$
|
752
|
|
|
$
|
297
|
|
|
$
|
(45
|
)
|
|
$
|
44
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
2015
|
|
2014
|
|||||
|
(in millions)
|
|||||||
Proved
|
|
|
|
|||||
Eagle Ford
|
$
|
2,833
|
|
|
$
|
5,862
|
|
|
Wolfcamp
|
2,174
|
|
|
1,933
|
|
|||
Altamont
|
1,553
|
|
|
1,275
|
|
|||
Haynesville
|
500
|
|
|
442
|
|
|||
Total Proved
|
7,060
|
|
|
9,512
|
|
|||
Unproved
|
|
|
|
|||||
Eagle Ford
|
—
|
|
|
131
|
|
|||
Wolfcamp
|
97
|
|
|
383
|
|
|||
Altamont
|
64
|
|
|
201
|
|
|||
Haynesville
|
7
|
|
|
14
|
|
|||
Total Unproved
|
168
|
|
|
729
|
|
|||
Less accumulated depletion
|
2,516
|
|
|
1,560
|
|
|||
Net capitalized costs for oil and natural gas properties
|
$
|
4,712
|
|
|
$
|
8,681
|
|
|
2015
|
|
2014
|
||||
|
(in millions)
|
||||||
Net asset retirement liability at January 1
|
$
|
42
|
|
|
$
|
30
|
|
Liabilities incurred
|
4
|
|
|
10
|
|
||
Liabilities settled
|
(2
|
)
|
|
(2
|
)
|
||
Accretion expense
|
3
|
|
|
3
|
|
||
Changes in estimate
|
(6
|
)
|
|
2
|
|
||
Other
|
—
|
|
|
(1
|
)
|
||
Net asset retirement liability at December 31
|
$
|
41
|
|
|
$
|
42
|
|
|
Interest Rate
|
|
December 31, 2015
|
|
December 31, 2014
|
|||||
|
|
|
(in millions)
|
|||||||
$2.75 billion RBL credit facility - due May 24, 2019
|
Variable
|
|
|
$
|
1,072
|
|
|
$
|
852
|
|
Senior secured term loan - due May 24, 2018
(1)(3)
|
Variable
|
|
|
497
|
|
|
496
|
|
||
Senior secured term loan - due April 30, 2019
(2)(3)
|
Variable
|
|
|
150
|
|
|
150
|
|
||
Senior secured notes - due May 1, 2019
|
6.875
|
%
|
|
—
|
|
|
750
|
|
||
Senior unsecured notes - due May 1, 2020
|
9.375
|
%
|
|
2,000
|
|
|
2,000
|
|
||
Senior unsecured notes - due September 1, 2022
|
7.75
|
%
|
|
350
|
|
|
350
|
|
||
Senior unsecured notes - due June 15, 2023
|
6.375
|
%
|
|
800
|
|
|
—
|
|
||
|
|
|
|
4,869
|
|
|
4,598
|
|
||
Less unamortized debt issue costs
|
|
|
(57
|
)
|
|
(65
|
)
|
|||
Total long-term debt
|
|
|
$
|
4,812
|
|
|
$
|
4,533
|
|
|
(1)
|
The term loan was issued at
99%
of par and carries interest at a specified margin over the
LIBOR
of
2.75%
, with a minimum
LIBOR
floor of
0.75%
. As of
December 31, 2015
and 2014, the effective interest rate of the term loan was
3.50%
.
|
(2)
|
The term loan carries interest at a specified margin over the
LIBOR
of
3.50%
, with a minimum
LIBOR
floor of
1.00%
. As of
December 31, 2015
and 2014, the effective interest rate for the term loan was
4.50%
.
|
(3)
|
The term loans are secured by a second priority lien on all of the collateral securing the RBL credit facility, and effectively rank junior to any existing and future first lien secured indebtedness of the Company.
|
Credit Facility
|
|
Maturity
Date
|
|
Interest
Rate
|
|
Commitment fees
|
$2.75 billion RBL
|
|
May 24, 2019
|
|
LIBOR + 1.75%
(1)
1.75% for LCs
|
|
0.375% commitment fee on unused capacity
|
|
(1)
|
Based on our
December 31, 2015
borrowing level. Amounts outstanding under the
$2.75 billion
RBL Facility bear interest at specified margins over the
LIBOR
of between
1.50%
and
2.50%
for Eurodollar loans or at specified margins over the Alternative Base Rate (
ABR
) of between
0.50%
and
1.50%
for
ABR
loans. Such margins will fluctuate based on the utilization of the facility.
|
Year Ending December 31,
|
|
Operating Leases
|
||
|
|
(in millions)
|
||
2016
|
|
$
|
12
|
|
2017
|
|
13
|
|
|
2018
|
|
9
|
|
|
Total
|
|
$
|
34
|
|
|
Number of Shares
|
|
Weighted Average
Grant Date Fair Value
per Share
|
|||
Non-vested at December 31, 2014
|
1,033,394
|
|
|
$
|
19.80
|
|
Granted
|
3,678,997
|
|
|
$
|
9.40
|
|
Vested
|
(336,268
|
)
|
|
$
|
19.59
|
|
Forfeited
|
(388,469
|
)
|
|
$
|
12.03
|
|
Non-vested at December 31, 2015
|
3,987,654
|
|
|
$
|
10.98
|
|
|
Number of Shares
Underlying
Options
|
|
Weighted
Average
Exercise Price
per Share
|
|
Weighted
Average
Remaining
Contractual
Term
|
|
Aggregate
Intrinsic Value
|
||||
|
|
|
|
|
(in years)
|
|
(in millions)
|
||||
Outstanding at December 31, 2014
|
219,352
|
|
|
$
|
19.82
|
|
|
|
|
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
Vested
|
(638
|
)
|
|
$
|
19.82
|
|
|
|
|
|
|
Forfeited or canceled
|
(4,377
|
)
|
|
$
|
19.82
|
|
|
|
|
|
|
Outstanding at December 31, 2015
|
214,337
|
|
|
$
|
19.82
|
|
|
8.25
|
|
—
|
|
2015
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Physical sales
|
|
$
|
290
|
|
|
$
|
368
|
|
|
$
|
319
|
|
|
$
|
264
|
|
Financial derivatives
|
|
203
|
|
|
(179
|
)
|
|
434
|
|
|
209
|
|
||||
Operating income (loss)
|
|
113
|
|
|
(208
|
)
|
|
355
|
|
|
(4,215
|
)
|
||||
Income tax expense (benefit)
|
|
10
|
|
|
(118
|
)
|
|
95
|
|
|
(565
|
)
|
||||
Income (loss) from continuing operations
|
|
19
|
|
|
(212
|
)
|
|
176
|
|
|
(3,731
|
)
|
||||
Net income (loss)
|
|
19
|
|
|
(212
|
)
|
|
176
|
|
|
(3,731
|
)
|
||||
Basic and diluted net income (loss) per common share
|
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
|
$
|
0.08
|
|
|
$
|
(0.87
|
)
|
|
$
|
0.72
|
|
|
$
|
(15.29
|
)
|
Net income (loss)
|
|
$
|
0.08
|
|
|
$
|
(0.87
|
)
|
|
$
|
0.72
|
|
|
$
|
(15.29
|
)
|
2014
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Physical sales
|
|
$
|
511
|
|
|
$
|
566
|
|
|
$
|
572
|
|
|
$
|
450
|
|
Financial derivatives
|
|
(135
|
)
|
|
(290
|
)
|
|
381
|
|
|
1,029
|
|
||||
Operating (loss) income
|
|
(60
|
)
|
|
(100
|
)
|
|
573
|
|
|
1,080
|
|
||||
Income tax (benefit) expense
|
|
(56
|
)
|
|
(68
|
)
|
|
191
|
|
|
365
|
|
||||
(Loss) income from continuing operations
|
|
(100
|
)
|
|
(112
|
)
|
|
306
|
|
|
633
|
|
||||
Net (loss) income
|
|
(90
|
)
|
|
(118
|
)
|
|
305
|
|
|
634
|
|
||||
Basic and diluted net (loss) income per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
(Loss) income from continuing operations
|
|
$
|
(0.42
|
)
|
|
$
|
(0.46
|
)
|
|
$
|
1.25
|
|
|
$
|
2.60
|
|
Net (loss) income
|
|
$
|
(0.38
|
)
|
|
$
|
(0.49
|
)
|
|
$
|
1.25
|
|
|
$
|
2.60
|
|
|
2015
|
|
2014
|
||||
Oil and natural gas properties
|
$
|
7,228
|
|
|
$
|
10,241
|
|
Less accumulated depreciation, depletion and amortization
|
2,516
|
|
|
1,560
|
|
||
Net capitalized costs
(1)
|
$
|
4,712
|
|
|
$
|
8,681
|
|
|
(1)
|
During the year ended December 31, 2015, we recorded a non-cash impairment charge of approximately
$4.0 billion
of our proved properties in the Eagle Ford Shale and a non-cash impairment charge of
$288 million
of our unproved properties in our Wolfcamp Shale.
|
|
Year Ended December 31, 2015
(1)
|
||||||||||
|
U.S.
|
||||||||||
|
Natural Gas
(in Bcf)
|
|
Oil
(in MBbls)
|
|
NGLs
(in MBbls)
|
|
Equivalent
Volumes
(in MMBoe)
|
||||
Proved developed and undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
1,243
|
|
|
320,813
|
|
|
94,226
|
|
|
622.2
|
|
Revisions due to prices
|
(44
|
)
|
|
(16,288
|
)
|
|
(3,880
|
)
|
|
(27.5
|
)
|
Revisions other than prices
(2)
|
(294
|
)
|
|
(32,778
|
)
|
|
(6,422
|
)
|
|
(88.2
|
)
|
Extensions and discoveries
(3)
|
100
|
|
|
41,189
|
|
|
11,065
|
|
|
68.9
|
|
Purchase of reserves
|
9
|
|
|
7,883
|
|
|
1,252
|
|
|
10.6
|
|
Production
|
(76
|
)
|
|
(22,078
|
)
|
|
(5,366
|
)
|
|
(40.0
|
)
|
End of year
|
938
|
|
|
298,741
|
|
|
90,875
|
|
|
546.0
|
|
|
|
|
|
|
|
|
|
||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
464
|
|
|
128,396
|
|
|
32,474
|
|
|
238.1
|
|
End of year
|
530
|
|
|
131,804
|
|
|
36,442
|
|
|
256.6
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
779
|
|
|
192,417
|
|
|
61,752
|
|
|
384.1
|
|
End of year
|
408
|
|
|
166,937
|
|
|
54,432
|
|
|
289.4
|
|
|
(1)
|
Proved reserves were evaluated based on the average first day of the month spot price for the preceding 12-month period of
$50.28
per Bbl (WTI) and
$2.59
per MMBtu (Henry Hub).
|
(2)
|
Of the
88
MMBoe of revisions other than prices, 85 MMBoe were negative PUD revisions due to the impact of the SEC's five-year development rule after reductions in estimated capital in our long-range development plan based on the lower price environment.
|
(3)
|
Of the
69
MMBoe of extensions and discoveries, 18 MMBoe are in the Eagle Ford Shale, 32 MMBoe are in the Wolfcamp Shale, 19 MMBoe are in the Altamont area and less than 1 MMBoe are in the Haynesville Shale. Of the
69
MMBoe of extensions and discoveries, 52 MMBoe were liquids representing
76%
of EP Energy’s total extensions and discoveries.
|
|
Year Ended December 31, 2014
(1)(2)
|
||||||||||
|
U.S.
|
||||||||||
|
Natural Gas
(in Bcf)
|
|
Oil
(in MBbls)
|
|
NGLs
(in MBbls)
|
|
Equivalent
Volumes
(in MMBoe)
|
||||
Proved developed and undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
1,070
|
|
|
293,201
|
|
|
75,605
|
|
|
547.2
|
|
Revisions due to prices
|
205
|
|
|
(1,720
|
)
|
|
(538
|
)
|
|
31.9
|
|
Revisions other than prices
|
(31
|
)
|
|
(8,310
|
)
|
|
3,702
|
|
|
(9.8
|
)
|
Extensions and discoveries
(3)
|
146
|
|
|
59,242
|
|
|
19,805
|
|
|
103.3
|
|
Purchase of reserves
|
9
|
|
|
4,079
|
|
|
1,530
|
|
|
7.1
|
|
Sales of reserves in place
|
(83
|
)
|
|
(5,615
|
)
|
|
(1,738
|
)
|
|
(21.2
|
)
|
Production
|
(73
|
)
|
|
(20,064
|
)
|
|
(4,140
|
)
|
|
(36.3
|
)
|
End of year
|
1,243
|
|
|
320,813
|
|
|
94,226
|
|
|
622.2
|
|
|
|
|
|
|
|
|
|
||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
484
|
|
|
83,811
|
|
|
17,647
|
|
|
182.1
|
|
End of year
|
464
|
|
|
128,396
|
|
|
32,474
|
|
|
238.1
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
586
|
|
|
209,391
|
|
|
57,958
|
|
|
365.1
|
|
End of year
|
779
|
|
|
192,417
|
|
|
61,752
|
|
|
384.1
|
|
|
(1)
|
Proved reserves were evaluated based on the average first day of the month spot price for the preceding 12-month period of $94.99 per Bbl (WTI) and $4.34 per MMBtu (Henry Hub).
|
(2)
|
Reflects only U.S. oil and natural gas reserves. In 2014, we sold our Brazilian operations with a December 31, 2013 balance of proved developed and undeveloped reserves of 11.6 MMBoe, during 2014 our production was (1.1) MMBoe, positive revisions of 0.4 MMBoe, for a total sales of reserves in place of (10.9) MMBoe.
|
(3)
|
Of the 103 MMBoe of extensions and discoveries, 2 MMBoe were from assets sold, 68 MMBoe are in the Eagle Ford Shale, 19 MMBoe are in the Wolfcamp Shale, 14 MMBoe are in the Altamont area and 2 MMBoe are in the Haynesville Shale. Of the 103 MMBoe of extensions and discoveries, 79 MMBoe were liquids representing 77% of EP Energy’s total extensions and discoveries.
|
|
Year Ended December 31, 2013
(1)
|
||||||||||||||||||||||
|
U.S.
|
|
Brazil
|
|
Total
|
||||||||||||||||||
|
Natural
Gas
(in Bcf)
|
|
Oil
(in MBbls)
|
|
NGLs
(in MBbls)
|
|
Equivalent
Volumes
(in MMBoe)
|
|
Natural
Gas
(in Bcf)
|
|
Oil
(in MBbls)
|
|
Equivalent
Volumes
(in MMBoe)
|
|
Equivalent
Volumes
(in MMBoe)
|
||||||||
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
1,727
|
|
|
256,242
|
|
|
34,331
|
|
|
578.5
|
|
|
68
|
|
|
2,152
|
|
|
13.4
|
|
|
591.9
|
|
Revisions due to prices
|
83
|
|
|
376
|
|
|
166
|
|
|
14.4
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
14.4
|
|
Revisions other than prices
|
129
|
|
|
(36,322
|
)
|
|
20,459
|
|
|
5.6
|
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
|
5.6
|
|
Extensions and
discoveries
(2)
|
231
|
|
|
88,174
|
|
|
28,583
|
|
|
155.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
155.3
|
|
Sales of reserves in place
|
(965
|
)
|
|
(1,642
|
)
|
|
(5,108
|
)
|
|
(167.6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(167.6
|
)
|
Production
|
(135
|
)
|
|
(13,627
|
)
|
|
(2,826
|
)
|
|
(39.0
|
)
|
|
(9
|
)
|
|
(305
|
)
|
|
(1.8
|
)
|
|
(40.8
|
)
|
End of year
(3)
|
1,070
|
|
|
293,201
|
|
|
75,605
|
|
|
547.2
|
|
|
59
|
|
|
1,835
|
|
|
11.6
|
|
|
558.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
1,189
|
|
|
55,924
|
|
|
9,080
|
|
|
263.2
|
|
|
68
|
|
|
2,152
|
|
|
13.3
|
|
|
276.5
|
|
End of year
|
484
|
|
|
83,811
|
|
|
17,647
|
|
|
182.1
|
|
|
59
|
|
|
1,835
|
|
|
11.6
|
|
|
193.7
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
538
|
|
|
200,318
|
|
|
25,251
|
|
|
315.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
315.2
|
|
End of year
|
586
|
|
|
209,391
|
|
|
57,958
|
|
|
365.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
365.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Unconsolidated Affiliate — Four Star
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
150
|
|
|
2,148
|
|
|
5,967
|
|
|
33.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33.1
|
|
Revisions due to prices
|
5
|
|
|
66
|
|
|
191
|
|
|
1.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.1
|
|
Revisions other than prices
|
11
|
|
|
128
|
|
|
348
|
|
|
2.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.3
|
|
Sales of reserves in place
|
(156
|
)
|
|
(2,145
|
)
|
|
(6,179
|
)
|
|
(34.3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(34.3
|
)
|
Production
|
(10
|
)
|
|
(197
|
)
|
|
(327
|
)
|
|
(2.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2.2
|
)
|
End of year
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
140
|
|
|
2,111
|
|
|
5,289
|
|
|
30.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30.9
|
|
End of year
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
10
|
|
|
37
|
|
|
678
|
|
|
2.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.4
|
|
End of year
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total Combined
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
1,329
|
|
|
58,035
|
|
|
14,369
|
|
|
294.1
|
|
|
68
|
|
|
2,152
|
|
|
13.3
|
|
|
307.4
|
|
End of year
|
484
|
|
|
83,811
|
|
|
17,647
|
|
|
182.1
|
|
|
59
|
|
|
1,835
|
|
|
11.6
|
|
|
193.7
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
548
|
|
|
200,355
|
|
|
25,929
|
|
|
317.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
317.6
|
|
End of year
|
586
|
|
|
209,391
|
|
|
57,958
|
|
|
365.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
365.1
|
|
|
(1)
|
Proved reserves were evaluated based on the average first day of the month spot price for the preceding 12-month period of $96.94 per Bbl (WTI) and $3.67 per MMBtu (Henry Hub).
|
(2)
|
Of the 155 MMBoe of combined extensions and discoveries, including assets sold, 5 MMBoe are in the Altamont area, 91 MMBoe are in the Eagle Ford Shale, and 51 MMBoe are in the Wolfcamp Shale. There were no extensions or discoveries in Brazil. Of the 155 MMBoe of extensions and discoveries, 117 MMBoe were liquids representing 75% of EP Energy’s total extensions and discoveries.
|
|
(3)
|
Includes accretion expense on asset retirement obligations of $3 million for both of the years ended December 31,
2015
and
2014
and $4 million for the year ended December 31,
2013
.
|
(4)
|
Results for 2013 are reported as of September 10, 2013 (the date the investment was sold). Results do not include amortization of $8 million for the year ended December 31, 2013 related to cost in excess of our equity interest in the underlying net assets of Four Star. In addition, in 2013 we recorded an impairment of $20 million, not included in the table above.
|
|
U.S.
|
|
Brazil
|
|
Worldwide
|
||||||
2013 Consolidated:
|
|
|
|
|
|
|
|
|
|||
Future cash inflows
(1)(2)
|
$
|
32,577
|
|
|
$
|
615
|
|
|
$
|
33,192
|
|
Future production costs
(2)
|
(9,083
|
)
|
|
(365
|
)
|
|
(9,448
|
)
|
|||
Future development costs
|
(6,789
|
)
|
|
(71
|
)
|
|
(6,860
|
)
|
|||
Future income tax expenses
|
(5,708
|
)
|
|
(18
|
)
|
|
(5,726
|
)
|
|||
Future net cash flows
|
10,997
|
|
|
161
|
|
|
11,158
|
|
|||
10% annual discount for estimated timing of cash flows
|
(5,488
|
)
|
|
(32
|
)
|
|
(5,520
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
5,509
|
|
|
$
|
129
|
|
|
$
|
5,638
|
|
|
(1)
|
The company had no commodity-based derivative contracts designated as accounting hedges at December 31,
2015
,
2014
and
2013
. Amounts also exclude the impact on future net cash flows of derivatives not designated as accounting hedges.
|
(2)
|
For 2013, U.S. future cash inflows and U.S. production costs include an adjustment of $(1,142) million and $104 million, respectively, to reflect an adjustment made to the prices used to calculate the standardized measure of discounted future net cash flows at December 31, 2013. Due to this change, future income taxes and 10% annual discount for estimated timing of cash flows changed accordingly, for a total net adjustment to the originally reported standardized measure of discounted future net cash flows of $(341) million.
|
|
Year Ended December 31,
(1)
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Consolidated:
|
|
|
|
|
|
|
|
|
|||
Sales and transfers of oil and natural gas produced net of production costs
|
$
|
(982
|
)
|
|
$
|
(1,785
|
)
|
|
$
|
(1,493
|
)
|
Net changes in prices and production costs
|
(7,085
|
)
|
|
(762
|
)
|
|
(745
|
)
|
|||
Extensions, discoveries and improved recovery, less related costs
|
145
|
|
|
1,728
|
|
|
2,626
|
|
|||
Changes in estimated future development costs
|
997
|
|
|
63
|
|
|
(10
|
)
|
|||
Previously estimated development costs incurred during the period
|
835
|
|
|
1,192
|
|
|
679
|
|
|||
Revision of previous quantity estimates
|
(1,008
|
)
|
|
441
|
|
|
447
|
|
|||
Accretion of discount
|
954
|
|
|
833
|
|
|
796
|
|
|||
Net change in income taxes
|
2,428
|
|
|
384
|
|
|
(2,864
|
)
|
|||
Purchase of reserves in place
|
48
|
|
|
137
|
|
|
—
|
|
|||
Sales of reserves in place
|
—
|
|
|
(229
|
)
|
|
(886
|
)
|
|||
Change in production rates, timing and other
|
(1,246
|
)
|
|
(613
|
)
|
|
27
|
|
|||
Net change
|
$
|
(4,914
|
)
|
|
$
|
1,389
|
|
|
$
|
(1,423
|
)
|
Unconsolidated Affiliate — Four Star:
(2)
|
|
|
|
|
|
|
|
|
|||
Sales and transfers of oil and natural gas produced net of production costs
|
|
|
|
|
|
|
$
|
(41
|
)
|
||
Net changes in prices and production costs
|
|
|
|
|
|
|
6
|
|
|||
Extensions, discoveries and improved recovery, less related costs
|
|
|
|
|
|
|
—
|
|
|||
Changes in estimated future development costs
|
|
|
|
|
|
|
25
|
|
|||
Revision of previous quantity estimates
|
|
|
|
|
|
|
10
|
|
|||
Accretion of discount
|
|
|
|
|
|
|
18
|
|
|||
Net change in income taxes
|
|
|
|
|
|
|
68
|
|
|||
Sales of reserves in place
|
|
|
|
|
|
|
(260
|
)
|
|||
Change in production rates, timing and other
|
|
|
|
|
|
|
38
|
|
|||
Net change
|
|
|
|
|
|
|
$
|
(136
|
)
|
||
|
|
|
|
|
|
||||||
Representative NYMEX prices:
(3)
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl)
|
$
|
50.28
|
|
|
$
|
94.99
|
|
|
$
|
96.94
|
|
Natural gas (MMBtu)
|
$
|
2.59
|
|
|
$
|
4.34
|
|
|
$
|
3.67
|
|
Aggregate International prices:
(3)
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl)
|
|
|
|
|
|
|
$
|
108.02
|
|
||
Natural gas (MMBtu)
|
|
|
|
|
|
|
$
|
6.31
|
|
|
(3)
|
First day 12-month historical average U.S. price and an aggregate international price before price differentials and deducts. Price differentials and deducts were applied when the estimated future cash flows from estimated production from proved reserves were calculated.
|
|
|
Page
|
|
3. and (b). Exhibits
|
|
101
|
|
|
EP ENERGY CORPORATION
|
|
|
|
|
|
By:
|
/s/ Brent J. Smolik
|
|
|
Brent J. Smolik
|
|
|
President and Chief Executive Officer
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Brent J. Smolik
|
|
|
|
|
Brent J. Smolik
|
|
President, Chief Executive Officer and
Chairman of the Board (Principal
Executive Officer)
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Dane E. Whitehead
|
|
|
|
|
Dane E. Whitehead
|
|
Executive Vice President and Chief
Financial Officer
(Principal Financial Officer)
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Francis C. Olmsted III
|
|
|
|
|
Francis C. Olmsted III
|
|
Vice President and Controller
(Principal Accounting Officer)
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Ralph Alexander
|
|
|
|
|
Ralph Alexander
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Gregory A. Beard
|
|
|
|
|
Gregory A. Beard
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Wilson B. Handler
|
|
|
|
|
Wilson B. Handler
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ John J. Hannan
|
|
|
|
|
John J. Hannan
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Michael S. Helfer
|
|
|
|
|
Michael S. Helfer
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Thomas R. Hix
|
|
|
|
|
Thomas R. Hix
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Jaegu Nam
|
|
|
|
|
Jaegu Nam
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Keith O. Rattie
|
|
|
|
|
Keith O. Rattie
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Robert M. Tichio
|
|
|
|
|
Robert M. Tichio
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Donald A. Wagner
|
|
|
|
|
Donald A. Wagner
|
|
Director
|
|
February 19, 2016
|
|
|
|
|
|
/s/ Rakesh Wilson
|
|
|
|
|
Rakesh Wilson
|
|
Director
|
|
February 19, 2016
|
Exhibit No.
|
|
Exhibit Description
|
2.1
|
|
Purchase and Sale Agreement among EP Energy Corporation, EP Energy Holding Company and El Paso Brazil, L.L.C., as sellers, and EPE Acquisition, LLC, as purchaser, dated as of February 24, 2012 (Exhibit 2.1 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
2.2
|
|
Amendment No. 1 to Purchase and Sale Agreement, dated as of April 16, 2012, among EP Energy, L.L.C. (f/k/a EP Energy Corporation), EP Energy Holding Company, El Paso Brazil, L.L.C. and EPE Acquisition, LLC (Exhibit 2.2 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
2.3
|
|
Amendment No. 2 to Purchase and Sale Agreement, dated as of May 24, 2012, among EP Energy, L.L.C. (f/k/a EP Energy Corporation), EP Energy Holding Company, El Paso Brazil, L.L.C., EP Production International Cayman Company, EPE Acquisition, LLC and solely for purposes of Sections 2 and 5 thereunder, El Paso LLC (Exhibit 2.3 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
3.1
|
|
Second Amended and Restated Certificate of Incorporation of EP Energy Corporation (Exhibit 3.1 to Company’s Current Report on Form 8-K, filed with the SEC on January 23, 2014).
|
|
|
|
3.2
|
|
Amended and Restated Bylaws of EP Energy Corporation (Exhibit 3.2 to Company’s Current Report on Form 8-K, filed with the SEC on January 23, 2014).
|
|
|
|
4.1
|
|
Indenture, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC) and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 9.375% Senior Notes due 2020 (Exhibit 4.2 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
4.2
|
|
Indenture, dated as of August 13, 2012, between EP Energy LLC and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 7.750% Senior Notes due 2022 (Exhibit 4.3 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
4.3
|
|
Indenture, dated as of May 28, 2015, between EP Energy LLC and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 6.375% Senior Notes due 2023 (Exhibit 4.3 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on June 24, 2015).
|
|
|
|
4.4
|
|
Registration Rights Agreement, dated as of May 28, 2015, between EP Energy LLC, Everest Acquisition Finance Inc. and RBC Capital Markets, LLC, as representative of the several initial purchasers, in respect of 6.375% Senior Notes due 2023 (Exhibit 4.5 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on June 24, 2015).
|
|
|
|
4.5
|
|
Registration Rights Agreement, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC), Everest Acquisition Finance Inc. and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the several initial purchasers, in respect of 9.375% Senior Notes due 2020 (Exhibit 4.5 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
4.6
|
|
Registration Rights Agreement, dated as of August 13, 2012, between EP Energy LLC, Everest Acquisition Finance Inc. and Citigroup Global Markets Inc., as representative of the several initial purchasers, in respect of 7.750% Senior Notes due 2022 (Exhibit 4.6 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
4.7
|
|
Registration Rights Agreement, dated as of August 30, 2013, between EP Energy Corporation and the stockholders party thereto (Exhibit 4.8 to the Company’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
|
Exhibit No.
|
|
Exhibit Description
|
10.1
|
|
Credit Agreement, dated as of May 24, 2012, by and among EPE Holdings, LLC, as Holdings, EP Energy LLC (f/k/a Everest Acquisition LLC), as the Borrower, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the other parties party thereto (Exhibit 10.1 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.2
|
|
Guarantee Agreement, dated as of May 24, 2012, by and among EPE Holdings LLC, the Domestic Subsidiaries of the Borrower signatory thereto and JPMorgan Chase Bank, N.A., as collateral agent for the Secured Parties referred to therein (Exhibit 10.2 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.3
|
|
Collateral Agreement, dated as of May 24, 2012, by and among EPE Holdings LLC, EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.3 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.4
|
|
Pledge Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.4 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.5
|
|
Pledge Agreement, dated as of May 24, 2012, by and among El Paso Brazil, L.L.C., as Pledgor, and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.5 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.6
|
|
Amendment, dated as of August 17, 2012, to the Credit Agreement, dated as of May 24, 2012, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.15 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.7
|
|
Second Amendment, dated as of March 27, 2013, to the Credit Agreement, dated as of May 24, 2012, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to EP Energy LLC’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, filed with the SEC on May 9, 2013).
|
|
|
|
10.8
|
|
Third Amendment, dated as of October 27, 2014, to the Credit Agreement, dated as of May 24, 2012, among EPE Acquisition, LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, filed with the SEC on April 30, 2015).
|
|
|
|
10.9
|
|
Fourth Amendment, dated as of April 6, 2014, to the Credit Agreement, dated as of May 24, 2012, among EPE Acquisition, LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on April 6, 2015).
|
|
|
|
10.10
|
|
Consent and Agreement to Credit Agreement, dated as of June 7, 2013, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.3 to EP Energy LLC’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, filed with the SEC on August 14, 2013).
|
|
|
|
10.11
|
|
Assumption and Ratification Agreement, dated as of April 30, 2014, entered into by EPE Acquisition, LLC, in favor of the Secured Parties (as defined in the Credit Agreement) (Exhibit 10.9 to Company’s Annual Report on Form 10-K filed with the SEC on February 23, 2015).
|
|
|
|
10.12
|
|
Senior Lien Intercreditor Agreement, dated as of May 24, 2012, among JPMorgan Chase Bank, N.A., as RBL Facility Agent and Applicable First Lien Agent, Citibank, N.A., as Term Facility Agent, Senior Secured Notes Collateral Agent and Applicable Second Lien Agent, Wilmington Trust, National Association, as Trustee under the Senior Secured Notes Indenture, EP Energy LLC and the Subsidiaries of EP Energy LLC named therein (Exhibit 10.6 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.13
|
|
Term Loan Agreement, dated as of April 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), as Borrower, the Lenders party thereto, Citibank, N.A., as Administrative Agent and Collateral Agent, and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as Co-Lead Arrangers (Exhibit 10.7 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.14
|
|
Guarantee Agreement, dated as of April 24, 2012, by and between Everest Acquisition Finance Inc., as Guarantor, and Citibank, N.A., as collateral agent for the Secured Parties referred to therein (Exhibit 10.8 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
Exhibit No.
|
|
Exhibit Description
|
10.15
|
|
Collateral Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as Collateral Agent (Exhibit 10.9 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.16
|
|
Pledge Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as Collateral Agent (Exhibit 10.10 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.17
|
|
Amendment No. 1, dated as of August 21, 2012, to the Term Loan Agreement, dated as of April 24, 2012, among EP Energy LLC, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.16 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.18
|
|
Joinder Agreement, dated as of August 21, 2012, among Citibank, N.A., as Additional Tranche B-1 Lender, EP Energy LLC and Citibank, N.A., as administrative agent (Exhibit 10.17 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.19
|
|
Incremental Facility Agreement, dated October 31, 2012, to the Term Loan Agreement, dated as of April 24, 2012 and amended by that certain Amendment No. 1 dated as of August 21, 2012, among EP Energy LLC, the lenders from time to time party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to EP Energy LLC’s Current Report on Form 8-K, filed with the SEC on October 31, 2012).
|
|
|
|
10.20
|
|
Reaffirmation Agreement, dated as of October 31, 2012, among EP Energy LLC, each Subsidiary Party party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.2 to EP Energy LLC’s Current Report on Form 8-K, filed with the SEC on October 31, 2012).
|
|
|
|
10.21
|
|
Amendment No. 2, dated as of May 2, 2013, to the Term Loan Agreement, dated as of April 24, 2012, among EP Energy LLC, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to EP Energy LLC’s Current Report on Form 8-K filed with the SEC on May 28, 2013).
|
|
|
|
10.22
|
|
Joinder Agreement, dated as of May 2, 2013, among Citibank, N.A., as Additional Tranche B-1 Lender, EP Energy LLC and Citibank, N.A., as administrative agent (Exhibit 10.2 to EP Energy LLC’s Current Report on Form 8-K filed with the SEC on May 28, 2013).
|
|
|
|
10.23
|
|
Pari Passu Intercreditor Agreement, dated as of May 24, 2012, among Citibank, N.A., as Second Lien Agent, Citibank, N.A., as Authorized Representative for the Term Loan Agreement, Wilmington Trust, National Association, as the Initial Other Authorized Representative and each additional Authorized Representative from time to time party hereto (Exhibit 10.12 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.24
|
|
Amended and Restated Management Fee Agreement, dated as of December 20, 2013, among EP Energy Corporation, EP Energy Global LLC, EPE Acquisition, LLC, Apollo Management VII, L.P., Apollo Commodities Management, L.P., With Respect to Series I, Riverstone V Everest Holdings, L.P., Access Industries, Inc. and Korea National Oil Corporation (Exhibit 10.23 to Amendment No. 4 to the Company’s Registration Statement on Form S-1, filed with the SEC on January 6, 2014).
|
|
|
|
10.25+
|
|
Employment Agreement dated May 24, 2012 for Clayton A. Carrell (Exhibit 10.18 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.26+
|
|
Employment Agreement dated May 24, 2012 for Brent J. Smolik (Exhibit 10.20 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.27+
|
|
Employment Agreement dated May 24, 2012 for Dane E. Whitehead (Exhibit 10.21 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.28+
|
|
Employment Agreement dated May 24, 2012 for Marguerite N. Woung-Chapman (Exhibit 10.22 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.29+
|
|
Employment Agreement dated May 24, 2012 for Joan M. Gallagher (Exhibit 10.30 to Company’s Annual Report on Form 10-K filed with the SEC on February 23, 2015).
|
|
|
|
10.30+
|
|
Senior Executive Survivor Benefit Plan adopted as of May 24, 2012 (Exhibit 10.23 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.31+
|
|
2012 Omnibus Incentive Plan (Exhibit 10.24 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
|
|
|
|
10.32+
|
|
Management Incentive Plan Agreement, dated as of August 30, 2013, between EP Energy Corporation and EPE Employee Holdings, LLC (Exhibit 10.31 to Amendment No. 2 to the Company’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013).†
|
|
|
|
Exhibit No.
|
|
Exhibit Description
|
10.33+
|
|
Form of EPE Employee Holdings, LLC Management Incentive Unit Agreement (Exhibit 10.26 to EP Energy LLC’s Registration Statement on Form S-4 filed with the SEC on September 11, 2012).
|
|
|
|
10.34+
|
|
Form of Notice to MIPs Holders regarding Corporate Reorganization (Exhibit 10.33 to the Company’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
|
|
|
|
10.35+
|
|
Third Amended and Restated Limited Liability Company Agreement of EPE Employee Holdings, LLC dated as of August 30, 2013 (Exhibit 10.34 to Amendment No. 2 to the Company’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013).†
|
|
|
|
10.36+
|
|
Third Amended and Restated Limited Liability Company Agreement of EPE Management Investors, LLC dated as of August 30, 2013 (Exhibit 10.35 to Amendment No. 2 to the Company’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013).†
|
|
|
|
10.37+
|
|
Subscription Agreement, dated as of August 30, 2013, between EP Energy Corporation and EPE Management Investors, LLC (Exhibit 10.36 to the Company’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
|
|
|
|
10.38+
|
|
Form of EP Energy Employee Holdings II, LLC Class B Incentive Pool Program Award Agreement (Exhibit 10.37 to Amendment No. 1 to the Company’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
|
|
|
|
10.39+
|
|
EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on January 23, 2014).
|
|
|
|
10.40+
|
|
Form of Notice Stock Option Grant and Stock Option Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.39 to Company’s Annual Report on Form 10-K filed with the SEC on February 27, 2014).
|
|
|
|
10.41+
|
|
Form of Notice Restricted Stock Grant and Restricted Stock Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.40 to Company’s Annual Report on Form 10-K filed with the SEC on February 27, 2014).
|
|
|
|
10.42+*
|
|
Form of Performance Unit Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan.
|
|
|
|
10.43
|
|
Stockholders Agreement, dated as of August 30, 2013, between EP Energy Corporation and the stockholders party
thereto (Exhibit 10.39 to Amendment No. 1 to the Company’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
|
|
|
|
10.44
|
|
Addendum Agreement, dated as of September 18, 2013, to the Stockholders Agreement, between EP Energy Corporation and EP Energy Employee Holdings II, LLC (Exhibit 10.40 to Amendment No. 1 to the Company’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
|
|
|
|
10.45
|
|
Form of Director and Officer Indemnification Agreement between EP Energy Corporation and each of the officers and directors thereof (Exhibit 10.41 to Amendment No. 4 to the Company’s Registration Statement on Form S-1, filed with the SEC on January 6, 2014).
|
|
|
|
12.1*
|
|
Ratio of Earnings to Fixed Charges
|
|
|
|
21.1*
|
|
Subsidiaries of EP Energy Corporation.
|
|
|
|
23.1*
|
|
Consent of Ernst & Young LLP, an independent registered public accounting firm.
|
|
|
|
23.2*
|
|
Consent of Ryder Scott Company, L.P.
|
|
|
|
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 of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
32.2*
|
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
99.1*
|
|
Ryder Scott Company, L.P. reserve audit report for EP Energy Corporation as of December 31, 2015.
|
|
|
|
Exhibit No.
|
|
Exhibit Description
|
101.INS*
|
|
XBRL Instance Document.
|
|
|
|
101.SCH*
|
|
XBRL Schema Document.
|
|
|
|
101.CAL*
|
|
XBRL Calculation Linkbase Document.
|
|
|
|
101.DEF*
|
|
XBRL Definition Linkbase Document.
|
|
|
|
101.LAB*
|
|
XBRL Labels Linkbase Document.
|
|
|
|
101.PRE*
|
|
XBRL Presentation Linkbase Document.
|
Name of Grantee:
|
|
Number of Performance Units
|
|
Target Value Per Unit
|
$100
|
Effective Date of Grant:
|
|
Performance Period(s):
|
[insert performance period(s)]
|
Vesting and Settlement Date
|
Subject to the terms of the Plan and the Performance Unit Award Agreement attached hereto, one-third of the Performance Units shall vest and be settled following the end of each Performance Period set forth above.
Settlement of each tranche of the award shall occur within 75 days following the end of the applicable Performance Period and Grantee must be employed by the Company on the settlement date to receive the payout.
|
Form of Settlement
|
Shares of Class A Common Stock of EP Energy Corporation (the “Company”), par value $0.01 per share (“Shares”), or cash, as determined by the Plan Administrator in its sole discretion
|
|
EP Energy Corporation
By:
Title:_____________________________
|
Relative TSR Position Compared to Peer Group
|
Value of
Performance Unit
*
|
Below 25th Percentile
|
$0
|
25th Percentile
|
$50
|
50th Percentile
|
$100
|
75th Percentile or Higher
|
$200
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||||||
|
Years Ended December 31,
|
|
February 14 to December 31,
|
|
|
January 1 to May 24,
|
|
Year Ended December 31,
|
||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
|
2012
|
|
2011
|
||||||||||||
Earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
(Loss) income from continuing operations before income taxes
|
$
|
(4,326
|
)
|
|
$
|
1,159
|
|
|
$
|
8
|
|
|
$
|
(306
|
)
|
|
|
$
|
321
|
|
|
$
|
628
|
|
Loss from equity investees
|
—
|
|
|
—
|
|
|
12
|
|
|
2
|
|
|
|
5
|
|
|
7
|
|
||||||
(Loss) income before income taxes before adjustment for loss from equity investees
|
(4,326
|
)
|
|
1,159
|
|
|
20
|
|
|
(304
|
)
|
|
|
326
|
|
|
635
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fixed charges
|
346
|
|
|
341
|
|
|
375
|
|
|
232
|
|
|
|
18
|
|
|
25
|
|
||||||
Distributed income of equity investees
|
—
|
|
|
—
|
|
|
24
|
|
|
14
|
|
|
|
8
|
|
|
46
|
|
||||||
Capitalized interest
|
(14
|
)
|
|
(21
|
)
|
|
(19
|
)
|
|
(12
|
)
|
|
|
(4
|
)
|
|
(10
|
)
|
||||||
Total earnings available for fixed charges
|
$
|
(3,994
|
)
|
|
$
|
1,479
|
|
|
$
|
400
|
|
|
$
|
(70
|
)
|
|
|
$
|
348
|
|
|
$
|
696
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fixed charges
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest and debt expense
|
$
|
344
|
|
|
$
|
339
|
|
|
$
|
373
|
|
|
$
|
231
|
|
|
|
$
|
18
|
|
|
$
|
25
|
|
Interest component of rent
|
2
|
|
|
2
|
|
|
2
|
|
|
1
|
|
|
|
—
|
|
|
—
|
|
||||||
Total fixed charges
|
$
|
346
|
|
|
$
|
341
|
|
|
$
|
375
|
|
|
$
|
232
|
|
|
|
$
|
18
|
|
|
$
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Ratio of earnings to fixed charges
(1)
|
—
|
|
|
4.35x
|
|
|
1.07x
|
|
|
—
|
|
|
|
19.33x
|
|
|
27.84x
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Earnings for the year ended December 31, 2015 were inadequate to cover fixed charges by $4,340 million, primarily due to non-cash impairment charges of approximately $4.3 billion associated with proved and unproved oil and natural gas properties related to a decline in commodity prices. Earnings for the period from February 14 to December 31, 2012 were inadequate to cover fixed charges by $302 million.
|
Subsidiary
|
|
Jurisdiction
|
|
% Owned
|
||
EPE Acquisition, LLC
|
|
Delaware
|
|
100
|
%
|
|
EP Energy LLC
|
|
Delaware
|
|
100
|
%
|
|
EP Energy Global LLC
|
|
Delaware
|
|
100
|
%
|
|
EP Energy Management, L.L.C.
|
|
Delaware
|
|
100
|
%
|
|
EP Energy Resale Company, L.L.C.
|
|
Delaware
|
|
100
|
%
|
|
EP Energy Gathering Company, L.L.C.
|
|
Delaware
|
|
100
|
%
|
|
EP Energy E&P Company, L.P.
1
|
|
Delaware
|
|
99
|
%
|
|
Crystal E&P Company, L.L.C.
|
|
Delaware
|
|
100
|
%
|
|
EnerVest Energy, L.P.
2
|
|
Delaware
|
|
23
|
%
|
|
Everest Acquisition Finance Inc.
|
|
Delaware
|
|
100
|
%
|
|
EPE Employee Holdings II, LLC
|
|
Delaware
|
|
100
|
%
|
|
Date:
|
February 19, 2016
|
|
|
|
|
|
|
|
|
/s/ Brent J. Smolik
|
|
|
|
Brent J. Smolik
|
|
|
|
Chairman, President and Chief Executive Officer
|
|
|
|
EP Energy Corporation
|
Date:
|
February 19, 2016
|
|
|
|
|
|
|
|
|
/s/ Dane E. Whitehead
|
|
|
|
Dane E. Whitehead
|
|
|
|
Executive Vice President and Chief Financial Officer
|
|
|
|
EP Energy Corporation
|
|
/s/ Brent J. Smolik
|
|
|
Brent J. Smolik
|
|
|
Chairman, President and
|
|
|
Chief Executive Officer
|
|
|
EP Energy Corporation
|
|
|
|
|
|
Date:
|
February 19, 2016
|
|
/s/ Dane E. Whitehead
|
|
|
Dane E. Whitehead
|
|
|
Executive Vice President and
|
|
|
Chief Financial Officer
|
|
|
EP Energy Corporation
|
|
|
|
|
|
Date:
|
February 19, 2016
|
\s\ Val Rick Robinson
|
Val Rick Robinson, P.E.
|
TBPE License No. 105137
|
Senior Vice President
|
Portions Reviewed
|
|||
EP Energy Leasehold and Royalty Interests
|
|||
|
|
|
|
|
Developed
|
Undeveloped
|
Total
|
Net Liquid Reserves
|
99%
|
100%
|
99%
|
Net Gas Reserves
|
97%
|
100%
|
98%
|
Net Equivalent Reserves
|
98%
|
100%
|
99%
|
Discount Future Net Income
|
98%
|
97%
|
98%
|
As of December 31, 2015
|
|
|
Proved
|
||||||
|
|
Developed
|
|
|
|
Total
|
||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
Net Reserves of Properties
Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBarrels
|
|
119,660
|
|
10,958
|
|
166,460
|
|
297,078
|
Plant Products - MBarrels
|
|
36,107
|
|
38
|
|
54,317
|
|
90,462
|
Gas – MMCF
|
|
491,908
|
|
21,953
|
|
407,383
|
|
921,244
|
Total Oil Equivalents – MBOE*
|
|
237,752
|
|
14,655
|
|
288,674
|
|
541,081
|
|
|
|
|
|
|
|
|
|
Net Reserves of Properties
Not Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Oil/Condensate – MBarrels
|
|
1,119
|
|
68
|
|
476
|
|
1,663
|
Plant Products – MBarrels
|
|
298
|
|
0
|
|
115
|
|
413
|
Gas – MMCF
|
|
15,761
|
|
290
|
|
1,080
|
|
17,131
|
Total Oil Equivalents – MBOE*
|
|
4,044
|
|
116
|
|
771
|
|
4,931
|
|
|
|
|
|
|
|
|
|
Total Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate – MBarrels
|
|
120,779
|
|
11,026
|
|
166,936
|
|
298,741
|
Plant Products – MBarrels
|
|
36,405
|
|
38
|
|
54,432
|
|
90,875
|
Gas – MMCF
|
|
507,669
|
|
22,243
|
|
408,463
|
|
938,375
|
Total Oil Equivalents – MBOE*
|
|
241,796
|
|
14,771
|
|
289,445
|
|
546,012
|
(1)
|
Gas Reference Price Hubs are: CenterPoint Energy Gas Transmission East, Colorado Interstate Gas Rocky Mntns, El Paso Natural Gas Co. Permian, Florida Gas Transmission (Zone 2), Henry Hub, Natural Gas Pipeline (South Texas zone), Houston Ship Channel, Tennessee Gas Pipeline Texas (Zone 0), Texas Eastern Transmission South Texas, Texas Gas Transmission Corp. (Zone 1), Transcontinental Gas Pipeline (Zone 3), Trunkline (Zone 1A), and West Texas Waha
|
(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.
|