Delaware
(State or other jurisdiction
of incorporation or organization)
|
41-0518430
(I.R.S. Employer Identification No.)
|
1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
|
80203
(Zip Code)
|
Title of each class
|
|
Name of each exchange on which registered
|
Common stock, $.01 par value
|
|
New York Stock Exchange
|
Large accelerated filer
þ
|
Accelerated filer
o
|
Non-accelerated filer
o
(Do not check if a smaller reporting company)
|
Smaller reporting company
o
|
|
||
TABLE OF CONTENTS
|
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ITEM
|
|
PAGE
|
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|
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|
||
|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
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|
TABLE OF CONTENTS
|
||
(Continued)
|
||
ITEM
|
|
PAGE
|
|
||
|
||
•
|
Resource Play Delineation and Development Results in Record Production and Record Year-End Proved Reserve Estimates.
Our estimated proved reserves increased
46 percent
to
428.7
MMBOE at
December 31, 2013
, from
293.4
MMBOE at
December 31, 2012
. We added
195.5
MMBOE through drilling activities during the year, which was led by our efforts in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We also achieved record levels of production in
2013
. Our average daily production was composed of
38.2
MBbl of oil,
409.2
MMcf of gas, and
26.0
MBbl of NGLs for an average equivalent production rate of
132.4
MBOE per day, which was an increase of
33 percent
from an average of
99.7
MBOE per day in
2012
. Costs incurred in
2013
for drilling and exploration activities and acquisitions remained essentially flat compared to 2012 at
$1.7 billion
. Please refer to
Core Operational Areas
below for additional discussion concerning our
2013
estimated proved reserves, production, and capital investment.
|
•
|
Divestiture Activity
. We continuously look to improve the quality of our asset portfolio through the divestiture of non-strategic properties. Our divestiture activity helps to generate cash that can be used to fund the acquisition or development of assets with higher potential value. During 2013, we sold a total of
18.2
MMBOE of reserves. We received
$445.8 million
in total cash proceeds at closing (referred throughout this report as “divestiture proceeds”) from these divestitures of non-strategic properties, with the sale of our Anadarko Basin assets in December 2013 being the most significant transaction.
|
•
|
Impairments.
We recorded impairment of proved properties expense of
$172.6 million
for the year ended
December 31, 2013
. The impairments in 2013 were a result of negative engineering revisions on Mississippian limestone assets in our Permian region at the end of the year, a plugging and abandonment program of our Olmos interval, dry gas assets in our South Texas & Gulf Coast region, and our decision to no longer pursue the development of certain under-performing assets during the year.
|
|
South Texas & Gulf Coast
|
|
Rocky
Mountain
|
|
Permian
|
|
Mid-
Continent
|
|
Total
(1)
|
||||||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
50.6
|
|
|
64.0
|
|
|
11.8
|
|
|
0.2
|
|
|
126.6
|
|
|||||
Gas (Bcf)
|
947.3
|
|
|
72.1
|
|
|
26.9
|
|
|
142.9
|
|
|
1,189.3
|
|
|||||
NGLs (MMBbl)
|
102.7
|
|
|
—
|
|
|
—
|
|
|
1.2
|
|
|
103.9
|
|
|||||
MMBOE
(1)
|
311.2
|
|
|
76.0
|
|
|
16.3
|
|
|
25.2
|
|
|
428.7
|
|
|||||
Relative percentage
|
73
|
%
|
|
18
|
%
|
|
4
|
%
|
|
6
|
%
|
|
100
|
%
|
|||||
Proved Developed %
|
42
|
%
|
|
59
|
%
|
|
91
|
%
|
|
78
|
%
|
|
49
|
%
|
|||||
PV-10 Values (in millions)
(2)
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved Developed
|
$
|
1,989.3
|
|
|
$
|
1,306.5
|
|
|
$
|
435.7
|
|
|
$
|
167.1
|
|
|
$
|
3,898.6
|
|
Proved Undeveloped
|
1,122.6
|
|
|
462.7
|
|
|
26.9
|
|
|
17.7
|
|
|
1,629.9
|
|
|||||
Total Proved
|
$
|
3,111.9
|
|
|
$
|
1,769.2
|
|
|
$
|
462.6
|
|
|
$
|
184.8
|
|
|
$
|
5,528.5
|
|
Relative percentage
|
56
|
%
|
|
32
|
%
|
|
8
|
%
|
|
3
|
%
|
|
100
|
%
|
|||||
Production
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
5.2
|
|
|
6.4
|
|
|
1.8
|
|
|
0.5
|
|
|
13.9
|
|
|||||
Gas (Bcf)
|
98.5
|
|
|
5.8
|
|
|
3.6
|
|
|
41.4
|
|
|
149.3
|
|
|||||
NGLs (MMBbl)
|
9.2
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
9.5
|
|
|||||
MMBOE
(1)
|
30.9
|
|
|
7.4
|
|
|
2.4
|
|
|
7.7
|
|
|
48.3
|
|
|||||
Avg. Daily Equivalents
(MBOE/d)
|
84.7
|
|
|
20.3
|
|
|
6.5
|
|
|
21.0
|
|
|
132.4
|
|
|||||
Relative percentage
|
64
|
%
|
|
15
|
%
|
|
5
|
%
|
|
16
|
%
|
|
100
|
%
|
|||||
Costs Incurred (in millions)
(3)
|
$
|
849.4
|
|
|
$
|
474.7
|
|
|
$
|
275.7
|
|
|
$
|
91.9
|
|
|
$
|
1,721.1
|
|
(1)
|
Totals may not sum or recalculate due to rounding.
|
(2)
|
The standardized measure PV-10 calculation is presented in the
Supplemental Oil and Gas Information
section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown in the
Reserves
section below.
|
(3)
|
Amounts do not sum to total costs incurred due to certain costs relating to our new venture projects being excluded from the regional table above.
|
|
As of December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Reserve data:
|
|
|
|
|
|
||||||
Proved developed
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
70.2
|
|
|
58.8
|
|
|
50.3
|
|
|||
Gas (Bcf)
|
569.2
|
|
|
483.2
|
|
|
451.2
|
|
|||
NGLs (MMBbl)
|
43.8
|
|
|
27.2
|
|
|
15.2
|
|
|||
MMBOE
(1)
|
208.9
|
|
|
166.5
|
|
|
140.7
|
|
|||
Proved undeveloped
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
56.3
|
|
|
33.5
|
|
|
21.4
|
|
|||
Gas (Bcf)
|
620.1
|
|
|
350.2
|
|
|
212.8
|
|
|||
NGLs (MMBbl)
|
60.2
|
|
|
35.1
|
|
|
12.3
|
|
|||
MMBOE
(1)
|
219.9
|
|
|
126.9
|
|
|
69.2
|
|
|||
Total Proved
(1)
|
|
|
|
|
|
||||||
Oil (MMBbl)
(1)
|
126.6
|
|
|
92.2
|
|
|
71.7
|
|
|||
Gas (Bcf)
(1)
|
1,189.3
|
|
|
833.4
|
|
|
664.0
|
|
|||
NGLs (MMBbl)
(1)
|
103.9
|
|
|
62.3
|
|
|
27.5
|
|
|||
MMBOE
(1)
|
428.7
|
|
|
293.4
|
|
|
209.9
|
|
|||
Proved developed reserves %
|
49
|
%
|
|
57
|
%
|
|
67
|
%
|
|||
Proved undeveloped reserves %
|
51
|
%
|
|
43
|
%
|
|
33
|
%
|
|||
|
|
|
|
|
|
||||||
Reserve value data (in millions):
|
|
|
|
|
|
||||||
Proved developed PV-10
|
$
|
3,898.6
|
|
|
$
|
2,982.6
|
|
|
$
|
2,836.3
|
|
Proved undeveloped PV-10
|
1,629.9
|
|
|
866.5
|
|
|
624.9
|
|
|||
Total proved PV-10
|
$
|
5,528.5
|
|
|
$
|
3,849.1
|
|
|
$
|
3,461.2
|
|
Standardized measure of discounted future cash flows
|
$
|
4,009.4
|
|
|
$
|
3,021.0
|
|
|
$
|
2,580.0
|
|
|
|
|
|
|
|
||||||
Reserve replacement – drilling, excluding revisions
|
405
|
%
|
|
411
|
%
|
|
310
|
%
|
|||
All in – including sales of reserves
|
380
|
%
|
|
329
|
%
|
|
262
|
%
|
|||
All in – excluding sales of reserves
|
418
|
%
|
|
337
|
%
|
|
317
|
%
|
|||
Reserve life (years)
|
8.9
|
|
|
8.0
|
|
|
7.4
|
|
|||
(1) Totals may not sum or recalculate due to rounding.
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Standardized measure of discounted future net cash flows
|
$
|
4,009.4
|
|
|
$
|
3,021.0
|
|
|
$
|
2,580.0
|
|
Add: 10 percent annual discount, net of income taxes
|
2,500.6
|
|
|
1,742.1
|
|
|
1,727.6
|
|
|||
Add: future undiscounted income taxes
|
2,722.2
|
|
|
1,609.4
|
|
|
1,740.4
|
|
|||
Undiscounted future net cash flows
|
9,232.2
|
|
|
6,372.5
|
|
|
6,048.0
|
|
|||
Less: 10 percent annual discount without tax effect
|
(3,703.7
|
)
|
|
(2,523.4
|
)
|
|
(2,586.8
|
)
|
|||
PV-10 value
|
$
|
5,528.5
|
|
|
$
|
3,849.1
|
|
|
$
|
3,461.2
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Net production
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
13.9
|
|
|
10.4
|
|
|
8.1
|
|
|||
Gas (Bcf)
|
149.3
|
|
|
120.0
|
|
|
100.3
|
|
|||
NGLs (MMBbl)
|
9.5
|
|
|
6.1
|
|
|
3.5
|
|
|||
MMBOE
(2)
|
48.3
|
|
|
36.5
|
|
|
28.3
|
|
|||
Eagle Ford net production
(1)
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
5.1
|
|
|
3.1
|
|
|
2.5
|
|
|||
Gas (Bcf)
|
97.1
|
|
|
58.1
|
|
|
32.9
|
|
|||
NGLs (MMBbl)
|
9.2
|
|
|
5.7
|
|
|
3.1
|
|
|||
MMBOE
(2)
|
30.5
|
|
|
18.5
|
|
|
11.1
|
|
|||
Average net daily production
|
|
|
|
|
|
||||||
Oil (MBbl per day)
|
38.2
|
|
|
28.3
|
|
|
22.1
|
|
|||
Gas (MMcf per day)
|
409.2
|
|
|
328.0
|
|
|
274.8
|
|
|||
NGLs (MBbl per day)
|
26.0
|
|
|
16.7
|
|
|
9.6
|
|
|||
MBOE per day
(2)
|
132.4
|
|
|
99.7
|
|
|
77.5
|
|
|||
Eagle Ford average net daily production
(1)
|
|
|
|
|
|
||||||
Oil (MBbl per day)
|
14.1
|
|
|
8.6
|
|
|
6.8
|
|
|||
Gas (MMcf per day)
|
265.9
|
|
|
158.8
|
|
|
90.1
|
|
|||
NGLs (MBbl per day)
|
25.2
|
|
|
15.5
|
|
|
8.6
|
|
|||
MBOE per day
(2)
|
83.6
|
|
|
50.5
|
|
|
30.4
|
|
|||
Realized price
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
91.19
|
|
|
$
|
85.45
|
|
|
$
|
88.23
|
|
Gas (per Mcf)
|
$
|
3.93
|
|
|
$
|
2.98
|
|
|
$
|
4.32
|
|
NGLs (per Bbl)
|
$
|
35.95
|
|
|
$
|
37.61
|
|
|
$
|
53.32
|
|
Per BOE
|
$
|
45.50
|
|
|
$
|
40.39
|
|
|
$
|
47.10
|
|
Production costs per BOE
|
|
|
|
|
|
||||||
Lease operating expense
|
$
|
4.82
|
|
|
$
|
4.93
|
|
|
$
|
5.30
|
|
Transportation costs
|
$
|
5.34
|
|
|
$
|
3.81
|
|
|
$
|
3.05
|
|
Production taxes
|
$
|
2.19
|
|
|
$
|
2.00
|
|
|
$
|
1.90
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
154
|
|
75.4
|
|
127
|
|
47.2
|
|
125
|
|
32.1
|
Gas
|
443
|
|
162.5
|
|
337
|
|
124.5
|
|
273
|
|
81.0
|
Non-productive
|
10
|
|
8.5
|
|
10
|
|
6.3
|
|
11
|
|
4.0
|
|
607
|
|
246.4
|
|
474
|
|
178.0
|
|
409
|
|
117.1
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
6
|
|
5.1
|
|
9
|
|
6.9
|
|
16
|
|
6.3
|
Gas
|
4
|
|
2.4
|
|
8
|
|
6.8
|
|
48
|
|
8.6
|
Non-productive
|
1
|
|
0.3
|
|
8
|
|
6.8
|
|
3
|
|
1.0
|
|
11
|
|
7.8
|
|
25
|
|
20.5
|
|
67
|
|
15.9
|
Total
|
618
|
|
254.2
|
|
499
|
|
198.5
|
|
476
|
|
133.0
|
|
Developed Acres
(1)
|
|
Undeveloped Acres
(2)
|
|
Total
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Louisiana
|
51,093
|
|
|
19,212
|
|
|
32,559
|
|
|
30,081
|
|
|
83,652
|
|
|
49,293
|
|
Montana
|
56,214
|
|
|
38,050
|
|
|
278,481
|
|
|
191,583
|
|
|
334,695
|
|
|
229,633
|
|
Nevada
|
—
|
|
|
—
|
|
|
197,634
|
|
|
197,634
|
|
|
197,634
|
|
|
197,634
|
|
North Dakota
|
155,150
|
|
|
107,170
|
|
|
68,960
|
|
|
37,049
|
|
|
224,110
|
|
|
144,219
|
|
Oklahoma
|
45,550
|
|
|
26,034
|
|
|
47,655
|
|
|
22,932
|
|
|
93,205
|
|
|
48,966
|
|
Texas
|
270,403
|
|
|
156,579
|
|
|
724,997
|
|
|
432,246
|
|
|
995,400
|
|
|
588,825
|
|
Wyoming
|
49,604
|
|
|
23,695
|
|
|
329,663
|
|
|
244,701
|
|
|
379,267
|
|
|
268,396
|
|
Other
(3)
|
4,872
|
|
|
2,451
|
|
|
55,736
|
|
|
40,955
|
|
|
60,608
|
|
|
43,406
|
|
|
632,886
|
|
|
373,191
|
|
|
1,735,685
|
|
|
1,197,181
|
|
|
2,368,571
|
|
|
1,570,372
|
|
Louisiana Fee Properties
|
10,499
|
|
|
10,499
|
|
|
14,415
|
|
|
14,415
|
|
|
24,914
|
|
|
24,914
|
|
Louisiana Mineral Servitudes
|
7,426
|
|
|
4,217
|
|
|
4,528
|
|
|
4,166
|
|
|
11,954
|
|
|
8,383
|
|
|
17,925
|
|
|
14,716
|
|
|
18,943
|
|
|
18,581
|
|
|
36,868
|
|
|
33,297
|
|
Total
(4)
|
650,811
|
|
|
387,907
|
|
|
1,754,628
|
|
|
1,215,762
|
|
|
2,405,439
|
|
|
1,603,669
|
|
(1)
|
Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation in each respective state. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but has been included only as developed acreage in the presentation above.
|
(2)
|
Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.
|
(3)
|
Includes interests in Arkansas, Colorado, Kansas, Illinois, Mississippi, Nebraska, New Mexico, Pennsylvania, and Utah.
|
(4)
|
As of the filing date of this report, we had 72,858, 174,694, and 170,314 net acres scheduled to expire by
December 31, 2014
,
2015
, and
2016
, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases.
|
Location
|
Approximate Square Footage
|
|
Leased Office Space:
|
|
|
Denver, CO
|
95,000
|
|
Houston, TX
|
62,000
|
|
Tulsa, OK
|
56,000
|
|
Midland, TX
|
22,000
|
|
Billings, MT
|
44,000
|
|
Williston & Watford City, ND
|
7,000
|
|
Casper, WY
|
4,000
|
|
Huntsville, TX
|
3,000
|
|
Total Leased Office Space
|
293,000
|
|
•
|
require the acquisition of various permits before drilling commences;
|
•
|
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;
|
•
|
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and
|
•
|
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
|
•
|
the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
|
•
|
the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions;
|
•
|
the possible divestiture or farm-down of, or joint venture relating to, certain properties;
|
•
|
proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates;
|
•
|
future oil, gas, and NGL production estimates;
|
•
|
our outlook on future oil, gas, and NGL prices, well costs, and service costs;
|
•
|
cash flows, anticipated liquidity, and the future repayment of debt;
|
•
|
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and
|
•
|
other similar matters such as those discussed in the
Management’s Discussion and Analysis of Financial Condition and Results of Operations
section in Item 7 of this report.
|
•
|
the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;
|
•
|
weakness in economic conditions and uncertainty in financial markets;
|
•
|
our ability to replace reserves in order to sustain production;
|
•
|
our ability to raise the substantial amount of capital that is required to develop and/or replace our reserves;
|
•
|
our ability to compete against competitors that have greater financial, technical, and human resources;
|
•
|
our ability to attract and retain key personnel;
|
•
|
the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;
|
•
|
the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;
|
•
|
the possibility that exploration and development drilling may not result in commercially producible reserves;
|
•
|
our limited control over activities on outside operated properties;
|
•
|
our reliance on the skill and expertise of third-party service providers on our operated properties;
|
•
|
the possibility that title to properties in which we have an interest may be defective;
|
•
|
the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;
|
•
|
the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;
|
•
|
the uncertainties associated with enhanced recovery methods;
|
•
|
our commodity derivative contracts may result in financial losses or may limit the prices that we receive for oil, gas, and NGL sales;
|
•
|
the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;
|
•
|
our ability to deliver necessary quantities of natural gas or crude oil to contractual counterparties;
|
•
|
price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
|
•
|
the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our credit facility;
|
•
|
the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;
|
•
|
the possibility that covenants in our debt agreements may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions or lead to the accelerated payment of our debt;
|
•
|
operating and environmental risks and hazards that could result in substantial losses;
|
•
|
the impact of seasonal weather conditions and lease stipulations on our ability to conduct drilling activities;
|
•
|
our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;
|
•
|
complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;
|
•
|
the availability and capacity of gathering, transportation, processing, and/or refining facilities;
|
•
|
our ability to sell and/or receive market prices for our oil, gas, and NGLs;
|
•
|
new technologies may cause our current exploration and drilling methods to become obsolete;
|
•
|
the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and
|
•
|
litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.
|
•
|
global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole;
|
•
|
the level of consumer demand for crude oil, natural gas, and NGLs;
|
•
|
overall global and domestic economic conditions;
|
•
|
weather conditions;
|
•
|
the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized price for crude oil, natural gas, or NGLs;
|
•
|
liquefied natural gas deliveries to and from the United States;
|
•
|
the price and level of imports and exports of crude oil, refined petroleum products, and liquefied natural gas;
|
•
|
the price and availability of alternative fuels;
|
•
|
technological advances and regulations affecting energy consumption and conservation;
|
•
|
the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to agree to and maintain crude oil price and production controls;
|
•
|
political instability or armed conflict in crude oil or natural gas producing regions;
|
•
|
strengthening and weakening of the United States dollar relative to other currencies; and
|
•
|
governmental regulations and taxes.
|
•
|
natural gas prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, leading to lower revenues, which could affect our financial condition and results of operations;
|
•
|
the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;
|
•
|
the liquidity available under our credit facility could be reduced if any lender is unable to fund its commitment;
|
•
|
our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for the exploration and/or development of reserves;
|
•
|
our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and
|
•
|
variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our credit facility.
|
•
|
amount and timing of actual production;
|
•
|
supply and demand for crude oil, natural gas, and NGLs;
|
•
|
curtailments or increases in consumption by oil purchasers and natural gas pipelines; and
|
•
|
changes in government regulations or taxes, including severance and excise taxes.
|
•
|
unexpected adverse drilling or completion conditions;
|
•
|
title problems;
|
•
|
disputes with owners or holders of surface interests on or near areas where we operate;
|
•
|
pressure or geologic irregularities in formations;
|
•
|
engineering and construction delays;
|
•
|
equipment failures or accidents;
|
•
|
hurricanes, tornadoes, flooding, or other adverse weather conditions;
|
•
|
governmental permitting delays;
|
•
|
compliance with environmental and other governmental requirements; and
|
•
|
shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.
|
•
|
our production is less than expected;
|
•
|
one or more counterparties to our commodity derivative contracts default on their contractual obligations; or
|
•
|
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.
|
•
|
making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;
|
•
|
requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments;
|
•
|
limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;
|
•
|
placing us at a competitive disadvantage compared to our competitors that have less debt; and
|
•
|
making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.
|
•
|
incur additional debt;
|
•
|
make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock;
|
•
|
sell assets, including capital stock of our subsidiaries;
|
•
|
restrict dividends or other payments of our subsidiaries;
|
•
|
create liens that secure debt;
|
•
|
enter into transactions with affiliates; and
|
•
|
merge or consolidate with another company.
|
•
|
the elimination of current deductions for intangible drilling and development costs;
|
•
|
the repeal of the percentage depletion allowance for oil and natural gas properties;
|
•
|
the elimination of the deduction for certain domestic production activities; and
|
•
|
an extension of the amortization period for certain geological and geophysical expenditures.
|
•
|
changes in crude oil, natural gas, or NGL prices;
|
•
|
variations in drilling, recompletion, and operating activity;
|
•
|
changes in financial estimates by securities analysts;
|
•
|
changes in market valuations of comparable companies;
|
•
|
additions or departures of key personnel;
|
•
|
future sales of our common stock; and
|
•
|
changes in the national and global economic outlook.
|
ITEM 5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
Quarter Ended
|
|
High
|
|
Low
|
||||
December 31, 2013
|
|
$
|
94.00
|
|
|
$
|
76.72
|
|
September 30, 2013
|
|
$
|
77.70
|
|
|
$
|
60.22
|
|
June 30, 2013
|
|
$
|
65.55
|
|
|
$
|
55.30
|
|
March 31, 2013
|
|
$
|
62.26
|
|
|
$
|
52.67
|
|
|
|
|
|
|
||||
December 31, 2012
|
|
$
|
62.09
|
|
|
$
|
45.25
|
|
September 30, 2012
|
|
$
|
59.39
|
|
|
$
|
39.44
|
|
June 30, 2012
|
|
$
|
71.81
|
|
|
$
|
43.12
|
|
March 31, 2012
|
|
$
|
84.40
|
|
|
$
|
69.40
|
|
ISSUER PURCHASES OF EQUITY SECURITIES
|
||||||||||||
|
Total Number of Shares Purchased
(1)
|
|
Average Price Paid per Share
|
|
Total Number of Shares Purchased as Part of Publicly Announced Program
|
|
Maximum Number of Shares that May Yet be Purchased Under the Program
(2)
|
|||||
January 1, 2013 -
March 31, 2013
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
April 1, 2013 -
June 30, 2013
|
390
|
|
|
$
|
59.84
|
|
|
—
|
|
|
3,072,184
|
|
July 1, 2013 -
September 30, 2013
|
267,362
|
|
|
$
|
60.50
|
|
|
—
|
|
|
3,072,184
|
|
October 1, 2013 -
October 31, 2013
|
285
|
|
|
$
|
77.19
|
|
|
—
|
|
|
3,072,184
|
|
November 1, 2013 -
November 30, 2013
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
December 1, 2013 -
December 31, 2013
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
Total October 1, 2013 -
December 31, 2013
|
285
|
|
|
$
|
77.19
|
|
|
—
|
|
|
3,072,184
|
|
Total
|
268,037
|
|
|
$
|
60.51
|
|
|
—
|
|
|
3,072,184
|
|
(1)
|
All shares purchased in
2013
were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under the Equity Plan.
|
(2)
|
In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indentures governing our Senior Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time. Please refer to
Dividends
above for a description of our dividend limitations.
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
||||||||||
|
(in millions, except per share data)
|
||||||||||||||||||
Total operating revenues
|
$
|
2,293.4
|
|
|
$
|
1,505.1
|
|
|
$
|
1,603.3
|
|
|
$
|
1,092.8
|
|
|
$
|
832.2
|
|
Net income (loss)
|
$
|
170.9
|
|
|
$
|
(54.2
|
)
|
|
$
|
215.4
|
|
|
$
|
196.8
|
|
|
$
|
(99.4
|
)
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
2.57
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.38
|
|
|
$
|
3.13
|
|
|
$
|
(1.59
|
)
|
Diluted
|
$
|
2.51
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.19
|
|
|
$
|
3.04
|
|
|
$
|
(1.59
|
)
|
Total assets at year-end
|
$
|
4,705.2
|
|
|
$
|
4,199.5
|
|
|
$
|
3,799.0
|
|
|
$
|
2,744.3
|
|
|
$
|
2,360.9
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revolving credit facility
|
$
|
—
|
|
|
$
|
340.0
|
|
|
$
|
—
|
|
|
$
|
48.0
|
|
|
$
|
188.0
|
|
3.50% Senior Convertible Notes, net of debt discount
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
285.1
|
|
|
$
|
275.7
|
|
|
$
|
266.9
|
|
Senior Notes
|
$
|
1,600.0
|
|
|
$
|
1,100.0
|
|
|
$
|
700.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Cash dividends declared and paid per common share
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
Supplemental Selected Financial and Operations Data
|
|||||||||||||||||||
|
|
||||||||||||||||||
|
For the Years Ended December 31,
|
||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
||||||||||
|
|
||||||||||||||||||
Balance Sheet Data (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Total working capital (deficit)
|
$
|
8.4
|
|
|
$
|
(201.0
|
)
|
|
$
|
(42.6
|
)
|
|
$
|
(227.4
|
)
|
|
$
|
(87.6
|
)
|
Total stockholders’ equity
|
$
|
1,606.8
|
|
|
$
|
1,414.5
|
|
|
$
|
1,462.9
|
|
|
$
|
1,218.5
|
|
|
$
|
973.6
|
|
Weighted-average common shares outstanding (in thousands)
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
66,615
|
|
|
65,138
|
|
|
63,755
|
|
|
62,969
|
|
|
62,457
|
|
|||||
Diluted
|
67,998
|
|
|
65,138
|
|
|
67,564
|
|
|
64,689
|
|
|
62,457
|
|
|||||
Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
126.6
|
|
|
92.2
|
|
|
71.7
|
|
|
57.4
|
|
|
53.8
|
|
|||||
Gas (Bcf)
|
1,189.3
|
|
|
833.4
|
|
|
664.0
|
|
|
640.0
|
|
|
449.5
|
|
|||||
NGLs (MMBbl)
|
103.9
|
|
|
62.3
|
|
|
27.5
|
|
|
—
|
|
|
—
|
|
|||||
MMBOE
|
428.7
|
|
|
293.4
|
|
|
209.9
|
|
|
164.1
|
|
|
128.7
|
|
|||||
Production and Operations (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil, gas, and NGL production revenue
|
$
|
2,199.6
|
|
|
$
|
1,473.9
|
|
|
$
|
1,332.4
|
|
|
$
|
836.3
|
|
|
$
|
616.0
|
|
Oil, gas, and NGL production expense
|
$
|
597.0
|
|
|
$
|
391.9
|
|
|
$
|
290.1
|
|
|
$
|
195.1
|
|
|
$
|
206.8
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion expense
|
$
|
822.9
|
|
|
$
|
727.9
|
|
|
$
|
511.1
|
|
|
$
|
336.1
|
|
|
$
|
304.2
|
|
General and administrative
|
$
|
149.6
|
|
|
$
|
119.8
|
|
|
$
|
118.5
|
|
|
$
|
106.7
|
|
|
$
|
76.0
|
|
Production Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
13.9
|
|
|
10.4
|
|
|
8.1
|
|
|
6.4
|
|
|
6.3
|
|
|||||
Gas (Bcf)
|
149.3
|
|
|
120.0
|
|
|
100.3
|
|
|
71.9
|
|
|
71.1
|
|
|||||
NGLs (MMBbl)
|
9.5
|
|
|
6.1
|
|
|
3.5
|
|
|
—
|
|
|
—
|
|
|||||
MMBOE
|
48.3
|
|
|
36.5
|
|
|
28.3
|
|
|
18.3
|
|
|
18.2
|
|
|||||
Realized price
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
$
|
91.19
|
|
|
$
|
85.45
|
|
|
$
|
88.23
|
|
|
$
|
72.65
|
|
|
$
|
54.40
|
|
Gas (per Mcf)
|
$
|
3.93
|
|
|
$
|
2.98
|
|
|
$
|
4.32
|
|
|
$
|
5.21
|
|
|
$
|
3.82
|
|
NGL (per Bbl)
|
$
|
35.95
|
|
|
$
|
37.61
|
|
|
$
|
53.32
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Adjusted price (net of derivative cash settlements)
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
$
|
89.92
|
|
|
$
|
83.52
|
|
|
$
|
78.89
|
|
|
$
|
66.85
|
|
|
$
|
56.74
|
|
Gas (per Mcf)
|
$
|
4.14
|
|
|
$
|
3.48
|
|
|
$
|
4.80
|
|
|
$
|
6.05
|
|
|
$
|
5.59
|
|
NGL (per Bbl)
|
$
|
36.66
|
|
|
$
|
38.90
|
|
|
$
|
47.90
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Expense per BOE
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expense
|
$
|
4.82
|
|
|
$
|
4.93
|
|
|
$
|
5.30
|
|
|
$
|
6.63
|
|
|
$
|
8.00
|
|
Transportation
|
$
|
5.34
|
|
|
$
|
3.81
|
|
|
$
|
3.05
|
|
|
$
|
1.15
|
|
|
$
|
1.14
|
|
Production taxes
|
$
|
2.19
|
|
|
$
|
2.00
|
|
|
$
|
1.90
|
|
|
$
|
2.86
|
|
|
$
|
2.24
|
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion expense
|
$
|
17.02
|
|
|
$
|
19.95
|
|
|
$
|
18.07
|
|
|
$
|
18.33
|
|
|
$
|
16.73
|
|
General and administrative
|
$
|
3.09
|
|
|
$
|
3.28
|
|
|
$
|
4.19
|
|
|
$
|
5.82
|
|
|
$
|
4.18
|
|
Statement of Cash Flow Data (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Provided by operating activities
|
$
|
1,338.5
|
|
|
$
|
922.0
|
|
|
$
|
760.5
|
|
|
$
|
497.1
|
|
|
$
|
436.1
|
|
Used in investing activities
|
$
|
(1,192.9
|
)
|
|
$
|
(1,457.3
|
)
|
|
$
|
(1,264.9
|
)
|
|
$
|
(361.6
|
)
|
|
$
|
(304.1
|
)
|
Provided by (used in) financing activities
|
$
|
130.7
|
|
|
$
|
422.1
|
|
|
$
|
618.5
|
|
|
$
|
(141.1
|
)
|
|
$
|
(127.5
|
)
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
At year-end
2013
, we had estimated proved reserves of
428.7
MMBOE, of which
54 percent
were liquids (oil and NGLs) and
49 percent
were characterized as proved developed. We added
195.5
MMBOE from our drilling program, the majority of which related to our activity in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We had slight price revisions that increased our estimated proved reserves by
0.6
MMBOE. The prices used in the calculation of proved reserve estimates as of
December 31, 2013
were
$96.94
per Bbl,
$3.67
per MMBtu, and
$40.29
per Bbl, for oil, gas, and NGLs, respectively. These prices were
two percent
and
33 percent
higher for oil and gas, respectively, and
12 percent
lower for NGLs than the prices used at year-end
2012
. We had upward engineering revisions of
7.2
MMBOE related primarily to Eagle Ford shale assets, offset partially by downward engineering revisions of certain legacy assets in our Permian region. Additionally, we removed
2.8
MMBOE of proved undeveloped gas reserves mainly in our South Texas & Gulf Coast region as a result of the five-year limitation on the number of years proved undeveloped reserves may remain on the books without being developed. Please refer to the caption
Proved Undeveloped Reserves
under the section
Reserves
included in Part I, Items 1 and 2 of this report for additional discussion. We had acquisitions of
1.3
MMBOE and we divested of
18.2
MMBOE of proved reserves during the year, most of which related to the sale of our Anadarko Basin properties. We also divested of certain other assets in our Mid-Continent, Rocky Mountain, and Permian regions.
|
•
|
The PV-10 value of our estimated proved reserves was
$5.5 billion
as of
December 31, 2013
, compared with
$3.8 billion
as of
December 31, 2012
. The after tax value, represented by the standardized measure calculation, was
$4.0 billion
as of
December 31, 2013
, compared with
$3.0 billion
as of
December 31, 2012
. The standardized measure calculation is presented in the
Supplemental Oil and Gas Information
section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown under
Reserves
in Part I, Items 1 and 2 of this report.
|
•
|
We had record annual production in
2013
. Our average daily production in
2013
was
38.2
MBbls of oil,
409.2
MMcf of gas, and
26.0
MBbls of NGLs, for an average daily equivalent production rate of
132.4
MBOE, compared with
99.7
MBOE in
2012
, an increase of
33 percent
year-over-year. Please refer to the caption
Production Results
below for additional discussion.
|
•
|
We recorded net income of
$170.9 million
, or
$2.51
per diluted share, for the year ended
December 31, 2013
. This compares with a net loss of
$54.2 million
, or a loss of
$0.83
per diluted share, for the year ended
December 31, 2012
. Please refer to the caption
Comparison of Financial Results and Trends Between
2013
and
2012
below for additional discussion regarding the components of net income (loss).
|
•
|
We had record cash flow provided by operating activities of
$1.3 billion
for the year ended
December 31, 2013
, compared with
$922.0 million
for the year ended
December 31, 2012
, which was an increase of
45 percent
year-over-year. Please refer to
Analysis of cash flow changes between
2013
and
2012
below for additional discussion.
|
•
|
We received net cash proceeds (net of marketing costs, Net Profits Plan payments, legal fees, and other selling costs paid) from the sale of oil and gas properties of
$424.8 million
for the year ended
December 31, 2013
. Please refer to
Analysis of cash flow changes between
2013
and
2012
below for additional discussion.
|
•
|
EBITDAX, a non-GAAP financial measure, for the year ended
December 31, 2013
, was
$1.5 billion
, compared with
$1.0 billion
for the same period in
2012
. Please refer to the caption
Non-GAAP Financial Measures
below for additional discussion, including our definition of EBITDAX and reconciliations of our GAAP net income (loss) and net cash provided by operating activities to EBITDAX.
|
•
|
Costs incurred for oil and gas producing activities for the year ended
December 31, 2013
, remained relatively flat at
$1.7 billion
when compared to the same period in
2012
. Please refer to the caption
Costs Incurred in Oil and Gas Producing Activities
below for additional discussion.
|
|
Reserve Replacement Percentage
|
|
Finding and Development Cost per BOE
(1)
|
||||||||||
|
Excluding Divestitures
|
|
Including Divestitures
|
|
Excluding Divestitures
|
|
Including Divestitures
|
||||||
Drilling, excluding revisions
|
405
|
%
|
|
367
|
%
|
|
$
|
7.77
|
|
|
$
|
8.56
|
|
Drilling, including revisions
|
415
|
%
|
|
377
|
%
|
|
$
|
7.57
|
|
|
$
|
8.33
|
|
Drilling and acquisitions, excluding revisions
|
407
|
%
|
|
370
|
%
|
|
$
|
7.87
|
|
|
$
|
8.67
|
|
Drilling and acquisitions, including revisions
|
418
|
%
|
|
380
|
%
|
|
$
|
7.67
|
|
|
$
|
8.43
|
|
All-in
|
418
|
%
|
|
380
|
%
|
|
$
|
8.53
|
|
|
$
|
9.37
|
|
|
Reserve Replacement Percentage
|
|
Finding and Development Cost per BOE
(1)
|
||||||||||
|
Excluding Divestitures
|
|
Including Divestitures
|
|
Excluding Divestitures
|
|
Including Divestitures
|
||||||
Drilling, excluding revisions
|
383
|
%
|
|
351
|
%
|
|
$
|
10.58
|
|
|
$
|
11.55
|
|
Drilling, including revisions
|
365
|
%
|
|
333
|
%
|
|
$
|
11.11
|
|
|
$
|
12.19
|
|
Drilling and acquisitions, excluding revisions
|
384
|
%
|
|
352
|
%
|
|
$
|
10.62
|
|
|
$
|
11.60
|
|
Drilling and acquisitions, including revisions
|
366
|
%
|
|
334
|
%
|
|
$
|
11.15
|
|
|
$
|
12.23
|
|
All-in
|
366
|
%
|
|
334
|
%
|
|
$
|
11.98
|
|
|
$
|
13.14
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Crude Oil (per Bbl):
|
|
|
|
|
|
||||||
Average NYMEX price
|
$
|
97.99
|
|
|
$
|
94.10
|
|
|
$
|
95.05
|
|
Realized price
|
$
|
91.19
|
|
|
$
|
85.45
|
|
|
$
|
88.23
|
|
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Average NYMEX price (per MMBtu)
|
$
|
3.73
|
|
|
$
|
2.75
|
|
|
$
|
4.00
|
|
Realized price (per Mcf)
|
$
|
3.93
|
|
|
$
|
2.98
|
|
|
$
|
4.32
|
|
|
|
|
|
|
|
||||||
NGLs (per Bbl):
|
|
|
|
|
|
||||||
Average OPIS price
|
$
|
40.44
|
|
|
$
|
44.91
|
|
|
$
|
59.47
|
|
Realized price
|
$
|
35.95
|
|
|
$
|
37.61
|
|
|
$
|
53.32
|
|
|
As of February 12, 2014
|
|
As of December 31, 2013
|
||||
NYMEX WTI oil (per Bbl)
|
$
|
96.31
|
|
|
$
|
95.79
|
|
NYMEX Henry Hub gas (per MMBtu)
|
$
|
4.64
|
|
|
$
|
4.19
|
|
OPIS NGLs (per Bbl)
|
$
|
40.49
|
|
|
$
|
41.17
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Crude Oil (per Bbl):
|
|
|
|
|
|
||||||
Realized price
|
$
|
91.19
|
|
|
$
|
85.45
|
|
|
$
|
88.23
|
|
Effects of derivative cash settlements
|
$
|
(1.27
|
)
|
|
$
|
(1.93
|
)
|
|
$
|
(9.34
|
)
|
|
|
|
|
|
|
||||||
Natural Gas (per Mcf):
|
|
|
|
|
|
||||||
Realized price
|
$
|
3.93
|
|
|
$
|
2.98
|
|
|
$
|
4.32
|
|
Effects of derivative cash settlements
|
$
|
0.21
|
|
|
$
|
0.50
|
|
|
$
|
0.48
|
|
|
|
|
|
|
|
||||||
NGLs (per Bbl):
|
|
|
|
|
|
||||||
Realized price
|
$
|
35.95
|
|
|
$
|
37.61
|
|
|
$
|
53.32
|
|
Effects of derivative cash settlements
|
$
|
0.71
|
|
|
$
|
1.29
|
|
|
$
|
(5.42
|
)
|
|
South Texas & Gulf Coast
|
|
Rocky
Mountain
|
|
Permian
|
|
Mid-Continent
|
|
Total
(1)
|
|||||
Production:
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MMBbl)
|
5.2
|
|
|
6.4
|
|
|
1.8
|
|
|
0.5
|
|
|
13.9
|
|
Gas (Bcf)
|
98.5
|
|
|
5.8
|
|
|
3.6
|
|
|
41.4
|
|
|
149.3
|
|
NGLs (MMBbl)
|
9.2
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
9.5
|
|
Equivalent (MMBOE)
(1)
|
30.9
|
|
|
7.4
|
|
|
2.4
|
|
|
7.7
|
|
|
48.3
|
|
Avg. Daily Equivalents (MBOE/d)
|
84.7
|
|
|
20.3
|
|
|
6.5
|
|
|
21.0
|
|
|
132.4
|
|
Relative percentage
|
64
|
%
|
|
15
|
%
|
|
5
|
%
|
|
16
|
%
|
|
100
|
%
|
|
For the Year Ended December 31, 2013
|
||
|
|||
|
(in millions)
|
||
Development costs
|
$
|
1,350.1
|
|
Exploration costs
|
168.6
|
|
|
Acquisitions
|
|
||
Proved properties
|
29.9
|
|
|
Unproved properties
|
172.5
|
|
|
Total, including asset retirement obligation
|
$
|
1,721.1
|
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2013
|
|
2013
|
|
2013
|
|
2013
|
||||||||
|
(in millions, except for production data)
|
||||||||||||||
Production (MMBOE)
|
13.2
|
|
|
12.8
|
|
|
12.0
|
|
|
10.3
|
|
||||
Oil, gas, and NGL production revenue
|
$
|
593.7
|
|
|
$
|
601.8
|
|
|
$
|
534.5
|
|
|
$
|
469.6
|
|
Lease operating expense
|
$
|
61.1
|
|
|
$
|
61.0
|
|
|
$
|
56.2
|
|
|
$
|
54.7
|
|
Transportation costs
|
$
|
75.0
|
|
|
$
|
68.8
|
|
|
$
|
67.0
|
|
|
$
|
47.4
|
|
Production taxes
|
$
|
26.7
|
|
|
$
|
29.1
|
|
|
$
|
26.5
|
|
|
$
|
23.5
|
|
DD&A
|
$
|
202.6
|
|
|
$
|
195.8
|
|
|
$
|
225.7
|
|
|
$
|
198.7
|
|
Exploration
|
$
|
21.8
|
|
|
$
|
16.3
|
|
|
$
|
20.7
|
|
|
$
|
15.4
|
|
General and administrative
|
$
|
48.0
|
|
|
$
|
33.9
|
|
|
$
|
35.4
|
|
|
$
|
32.3
|
|
Net income
|
$
|
7.0
|
|
|
$
|
70.7
|
|
|
$
|
76.5
|
|
|
$
|
16.7
|
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2013
|
|
2013
|
|
2013
|
|
2013
|
||||||||
Average net daily production equivalent (MBOE per day)
|
143.8
|
|
|
138.8
|
|
|
131.8
|
|
|
115.0
|
|
||||
Lease operating expense (per BOE)
|
$
|
4.62
|
|
|
$
|
4.77
|
|
|
$
|
4.69
|
|
|
$
|
5.28
|
|
Transportation costs (per BOE)
|
$
|
5.67
|
|
|
$
|
5.38
|
|
|
$
|
5.59
|
|
|
$
|
4.58
|
|
Production taxes as a percent of oil, gas, and NGL production revenue
|
4.5
|
%
|
|
4.8
|
%
|
|
5.0
|
%
|
|
5.0
|
%
|
||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion expense (per BOE)
|
$
|
15.31
|
|
|
$
|
15.33
|
|
|
$
|
18.82
|
|
|
$
|
19.20
|
|
General and administrative (per BOE)
|
$
|
3.63
|
|
|
$
|
2.66
|
|
|
$
|
2.95
|
|
|
$
|
3.12
|
|
|
For the Years Ended December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2013/2012
|
|
2012/2011
|
|
2013/2012
|
|
2012/2011
|
||||||||||||||
Net production volumes
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MMBbl)
|
13.9
|
|
|
10.4
|
|
|
8.1
|
|
|
3.6
|
|
|
2.3
|
|
|
34
|
%
|
|
28
|
%
|
|||||||
Gas (Bcf)
|
149.3
|
|
|
120.0
|
|
|
100.3
|
|
|
29.3
|
|
|
19.7
|
|
|
24
|
%
|
|
20
|
%
|
|||||||
NGLs (MMBbl)
|
9.5
|
|
|
6.1
|
|
|
3.5
|
|
|
3.4
|
|
|
2.6
|
|
|
55
|
%
|
|
75
|
%
|
|||||||
Equivalent (MMBOE)
|
48.3
|
|
|
36.5
|
|
|
28.3
|
|
|
11.8
|
|
|
8.2
|
|
|
32
|
%
|
|
29
|
%
|
|||||||
Average net daily production
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MBbl per day)
|
38.2
|
|
|
28.3
|
|
|
22.1
|
|
|
9.9
|
|
|
6.2
|
|
|
35
|
%
|
|
28
|
%
|
|||||||
Gas (MMcf per day)
|
409.2
|
|
|
328.0
|
|
|
274.8
|
|
|
81.2
|
|
|
53.1
|
|
|
25
|
%
|
|
19
|
%
|
|||||||
NGLs (MBbl per day)
|
26.0
|
|
|
16.7
|
|
|
9.6
|
|
|
9.3
|
|
|
7.1
|
|
|
56
|
%
|
|
75
|
%
|
|||||||
Equivalent (MBOE per day)
|
132.4
|
|
|
99.7
|
|
|
77.5
|
|
|
32.7
|
|
|
22.2
|
|
|
33
|
%
|
|
29
|
%
|
|||||||
Oil, gas, and NGL production revenue (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil production revenue
|
$
|
1,271.5
|
|
|
$
|
886.2
|
|
|
$
|
712.8
|
|
|
$
|
385.3
|
|
|
$
|
173.4
|
|
|
43
|
%
|
|
24
|
%
|
||
Gas production revenue
|
586.3
|
|
|
357.7
|
|
|
433.4
|
|
|
228.6
|
|
|
(75.7
|
)
|
|
64
|
%
|
|
(17
|
)%
|
|||||||
NGL production revenue
|
341.8
|
|
|
230.0
|
|
|
186.2
|
|
|
111.8
|
|
|
43.8
|
|
|
49
|
%
|
|
24
|
%
|
|||||||
Total
|
$
|
2,199.6
|
|
|
$
|
1,473.9
|
|
|
$
|
1,332.4
|
|
|
$
|
725.7
|
|
|
$
|
141.5
|
|
|
49
|
%
|
|
11
|
%
|
||
Oil, gas, and NGL production expense (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expenses
|
$
|
233.0
|
|
|
$
|
180.1
|
|
|
$
|
149.8
|
|
|
$
|
52.9
|
|
|
$
|
30.3
|
|
|
29
|
%
|
|
20
|
%
|
||
Transportation costs
|
258.2
|
|
|
138.9
|
|
|
86.4
|
|
|
119.3
|
|
|
52.5
|
|
|
86
|
%
|
|
61
|
%
|
|||||||
Production taxes
|
105.8
|
|
|
72.9
|
|
|
53.9
|
|
|
32.9
|
|
|
19.0
|
|
|
45
|
%
|
|
35
|
%
|
|||||||
Total
|
$
|
597.0
|
|
|
$
|
391.9
|
|
|
$
|
290.1
|
|
|
$
|
205.1
|
|
|
$
|
101.8
|
|
|
52
|
%
|
|
35
|
%
|
||
Realized price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (per Bbl)
|
$
|
91.19
|
|
|
$
|
85.45
|
|
|
$
|
88.23
|
|
|
$
|
5.74
|
|
|
$
|
(2.78
|
)
|
|
7
|
%
|
|
(3
|
)%
|
||
Gas (per Mcf)
|
$
|
3.93
|
|
|
$
|
2.98
|
|
|
$
|
4.32
|
|
|
$
|
0.95
|
|
|
$
|
(1.34
|
)
|
|
32
|
%
|
|
(31
|
)%
|
||
NGLs (per Bbl)
|
$
|
35.95
|
|
|
$
|
37.61
|
|
|
$
|
53.32
|
|
|
$
|
(1.66
|
)
|
|
$
|
(15.71
|
)
|
|
(4
|
)%
|
|
(29
|
)%
|
||
Per BOE
|
$
|
45.50
|
|
|
$
|
40.39
|
|
|
$
|
47.10
|
|
|
$
|
5.11
|
|
|
$
|
(6.71
|
)
|
|
13
|
%
|
|
(14
|
)%
|
||
Per BOE data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expense
|
$
|
4.82
|
|
|
$
|
4.93
|
|
|
$
|
5.30
|
|
|
$
|
(0.11
|
)
|
|
$
|
(0.37
|
)
|
|
(2
|
)%
|
|
(7
|
)%
|
||
Transportation costs
|
$
|
5.34
|
|
|
$
|
3.81
|
|
|
$
|
3.05
|
|
|
$
|
1.53
|
|
|
$
|
0.76
|
|
|
40
|
%
|
|
25
|
%
|
||
Production taxes
|
$
|
2.19
|
|
|
$
|
2.00
|
|
|
$
|
1.90
|
|
|
$
|
0.19
|
|
|
$
|
0.10
|
|
|
10
|
%
|
|
5
|
%
|
||
General and administrative
|
$
|
3.09
|
|
|
$
|
3.28
|
|
|
$
|
4.19
|
|
|
$
|
(0.19
|
)
|
|
$
|
(0.91
|
)
|
|
(6
|
)%
|
|
(22
|
)%
|
||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion expense
|
$
|
17.02
|
|
|
$
|
19.95
|
|
|
$
|
18.07
|
|
|
$
|
(2.93
|
)
|
|
$
|
1.88
|
|
|
(15
|
)%
|
|
10
|
%
|
||
Derivative cash settlement
(2)
|
$
|
(0.42
|
)
|
|
$
|
(1.32
|
)
|
|
$
|
1.64
|
|
|
$
|
0.90
|
|
|
$
|
(2.96
|
)
|
|
(68
|
)%
|
|
(180
|
)%
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Earnings per share information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Basic net income (loss) per common share
|
$
|
2.57
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.38
|
|
|
$
|
3.40
|
|
|
$
|
(4.21
|
)
|
|
410
|
%
|
|
(125
|
)%
|
||
Diluted net income (loss) per common share
|
$
|
2.51
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.19
|
|
|
$
|
3.34
|
|
|
$
|
(4.02
|
)
|
|
402
|
%
|
|
(126
|
)%
|
||
Basic weighted-average common shares outstanding (in thousands)
|
66,615
|
|
|
65,138
|
|
|
63,755
|
|
|
1,477
|
|
|
1,383
|
|
|
2
|
%
|
|
2
|
%
|
|||||||
Diluted weighted-average common shares outstanding (in thousands)
|
67,998
|
|
|
65,138
|
|
|
67,564
|
|
|
2,860
|
|
|
(2,426
|
)
|
|
4
|
%
|
|
(4
|
)%
|
|
Average Net Daily Production Added (Lost)
|
|
Oil, Gas & NGL Revenue Added
|
|
Production Costs Increase (Decrease)
|
|||||
|
(MBOE/d)
|
|
(in millions)
|
|
(in millions)
|
|||||
South Texas & Gulf Coast
|
33.4
|
|
|
$
|
515.5
|
|
|
$
|
159.2
|
|
Rocky Mountain
|
3.4
|
|
|
136.6
|
|
|
28.7
|
|
||
Permian
|
1.4
|
|
|
51.6
|
|
|
19.4
|
|
||
Mid-Continent
|
(5.5
|
)
|
|
22.0
|
|
|
(2.2
|
)
|
||
Total
|
32.7
|
|
|
$
|
725.7
|
|
|
$
|
205.1
|
|
|
For the Years Ended December 31,
|
||||||
|
2013
|
|
2012
|
||||
Realized oil price ($/Bbl)
|
$
|
91.19
|
|
|
$
|
85.45
|
|
Realized gas price ($/Mcf)
|
$
|
3.93
|
|
|
$
|
2.98
|
|
Realized NGL price ($/Bbl)
|
$
|
35.95
|
|
|
$
|
37.61
|
|
Realized equivalent price ($/BOE)
|
$
|
45.50
|
|
|
$
|
40.39
|
|
|
For the Years Ended December 31,
|
||||||
|
2013
|
|
2012
|
||||
Summary of Exploration Expense
|
(in millions)
|
||||||
Geological and geophysical expenses
|
$
|
4.3
|
|
|
$
|
13.6
|
|
Exploratory dry hole
|
5.8
|
|
|
20.9
|
|
||
Overhead and other expenses
|
64.0
|
|
|
55.7
|
|
||
Total
|
$
|
74.1
|
|
|
$
|
90.2
|
|
|
Average Net Daily Production Added (Lost)
|
|
Oil, Gas & NGL Revenue Added (Lost)
|
|
Production Costs Increase
|
|||||
|
(MBOE/d)
|
|
(in millions)
|
|
(in millions)
|
|||||
South Texas & Gulf Coast
|
19.5
|
|
|
$
|
137.0
|
|
|
$
|
68.9
|
|
Rocky Mountain
|
4.6
|
|
|
113.1
|
|
|
26.1
|
|
||
Permian
|
(0.1
|
)
|
|
(16.5
|
)
|
|
4.5
|
|
||
Mid-Continent
|
(1.8
|
)
|
|
(92.1
|
)
|
|
2.3
|
|
||
Total
|
22.2
|
|
|
$
|
141.5
|
|
|
$
|
101.8
|
|
|
For the Years Ended December 31,
|
||||||
|
2012
|
|
2011
|
||||
Realized oil price ($/Bbl)
|
$
|
85.45
|
|
|
$
|
88.23
|
|
Realized gas price ($/Mcf)
|
$
|
2.98
|
|
|
$
|
4.32
|
|
Realized NGL price ($/Bbl)
|
$
|
37.61
|
|
|
$
|
53.32
|
|
Realized equivalent price ($/BOE)
|
$
|
40.39
|
|
|
$
|
47.10
|
|
|
For the Years Ended December 31,
|
||||||
|
2012
|
|
2011
|
||||
Summary of Exploration Expense
|
(in millions)
|
||||||
Geological and geophysical expenses
|
$
|
13.6
|
|
|
$
|
7.3
|
|
Exploratory dry hole
|
20.9
|
|
|
0.3
|
|
||
Overhead and other expenses
|
55.7
|
|
|
45.9
|
|
||
Total
|
$
|
90.2
|
|
|
$
|
53.5
|
|
|
For the Years Ended December 31,
|
|||||||
|
2013
|
|
2012
|
|
2011
|
|||
Weighted-average interest rate
|
6.3
|
%
|
|
6.4
|
%
|
|
8.5
|
%
|
Weighted-average borrowing rate
|
5.7
|
%
|
|
5.5
|
%
|
|
5.2
|
%
|
|
|
For the Years Ended
December 31,
|
|
Amount of Changes Between
|
|
Percent of Change Between
|
||||||||||||||||||||
|
|
2013
|
|
2012
|
|
2011
|
|
2013/2012
|
|
2012/2011
|
|
2013/2012
|
|
2012/2011
|
||||||||||||
|
|
(in millions)
|
|
|
|
|
||||||||||||||||||||
Net cash provided by operating activities
|
|
$
|
1,338.5
|
|
|
$
|
922.0
|
|
|
$
|
760.5
|
|
|
$
|
416.5
|
|
|
$
|
161.5
|
|
|
45
|
%
|
|
21
|
%
|
Net cash used in investing activities
|
|
$
|
(1,192.9
|
)
|
|
$
|
(1,457.3
|
)
|
|
$
|
(1,264.9
|
)
|
|
$
|
264.4
|
|
|
$
|
(192.4
|
)
|
|
(18
|
)%
|
|
15
|
%
|
Net cash provided by financing activities
|
|
$
|
130.7
|
|
|
$
|
422.1
|
|
|
$
|
618.5
|
|
|
$
|
(291.4
|
)
|
|
$
|
(196.4
|
)
|
|
(69
|
)%
|
|
(32
|
)%
|
|
10% Increase
|
|
10% Decrease
|
||||
|
(in millions)
|
||||||
Gain/(loss):
|
|
|
|
||||
Oil derivatives
|
$
|
(151.0
|
)
|
|
$
|
144.7
|
|
Gas derivatives
|
$
|
(103.6
|
)
|
|
$
|
103.7
|
|
NGL derivatives
|
$
|
(15.5
|
)
|
|
$
|
15.5
|
|
Contractual Obligations
|
|
Total
|
|
Less than 1 year
|
|
1-3 years
|
|
3-5 years
|
|
More than 5 years
|
||||||||||
Long-term debt
(1)
|
|
$
|
1,600.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,600.0
|
|
Interest payments
(2)
|
|
843.9
|
|
|
105.7
|
|
|
203.6
|
|
|
200.1
|
|
|
334.5
|
|
|||||
Delivery commitments
(3)
|
|
1,070.9
|
|
|
112.6
|
|
|
263.8
|
|
|
247.0
|
|
|
447.5
|
|
|||||
Operating leases and contracts
(3)
|
|
142.7
|
|
|
66.5
|
|
|
27.8
|
|
|
14.0
|
|
|
34.4
|
|
|||||
Derivative liability
(4)
|
|
31.0
|
|
|
26.4
|
|
|
4.5
|
|
|
0.1
|
|
|
—
|
|
|||||
Net Profits Plan
(5)
|
|
59.4
|
|
|
14.3
|
|
|
21.5
|
|
|
16.8
|
|
|
6.8
|
|
|||||
Asset retirement obligations
(6)
|
|
121.2
|
|
|
25.8
|
|
|
9.4
|
|
|
5.3
|
|
|
80.7
|
|
|||||
Other
(7)
|
|
21.5
|
|
|
4.5
|
|
|
10.6
|
|
|
6.0
|
|
|
0.4
|
|
|||||
Total
|
|
$
|
3,890.6
|
|
|
$
|
355.8
|
|
|
$
|
541.2
|
|
|
$
|
489.3
|
|
|
$
|
2,504.3
|
|
(6)
|
Amount shown represents estimated future discounted abandonment costs. These obligations are recorded as liabilities on our accompanying balance sheet as of December 31, 2013. The ultimate settlement of these obligations is unknown and can be impacted by federal and state regulations, as well as economic factors and therefore the actual timing of abandonment costs may vary significantly. Please refer to
Note 9 – Asset Retirement Obligations
in Part II, Item 8 of this report for additional discussion regarding our asset retirement obligations.
|
|
For the Years Ended December 31,
|
|||||||
|
2013
|
|
2012
|
|
2011
|
|||
|
MMBOE
|
|
MMBOE
|
|
MMBOE
|
|||
|
Change
|
|
Change
|
|
Change
|
|||
Revisions resulting from price changes
|
0.6
|
|
|
(12.1
|
)
|
|
(4.2
|
)
|
Revisions resulting from performance
(1)
|
4.4
|
|
|
(15.3
|
)
|
|
6.1
|
|
Total
|
5.0
|
|
|
(27.4
|
)
|
|
1.9
|
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
|
MMBOE
|
|
Percentage
|
|
MMBOE
|
|
Percentage
|
|
MMBOE
|
|
Percentage
|
||||||
|
Change
|
|
Change
|
|
Change
|
|
Change
|
|
Change
|
|
Change
|
||||||
10% decrease in SEC pricing
|
(9.8
|
)
|
|
(2
|
)%
|
|
(11.2
|
)
|
|
(4
|
)%
|
|
(3.7
|
)
|
|
(2
|
)%
|
10% decrease in proved undeveloped reserves
|
(22.0
|
)
|
|
(5
|
)%
|
|
(12.7
|
)
|
|
(4
|
)%
|
|
(6.9
|
)
|
|
(3
|
)%
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
|
|
(in thousands)
|
||||||||||
Net income (loss) (GAAP)
|
$
|
170,935
|
|
|
$
|
(54,249
|
)
|
|
$
|
215,416
|
|
|
|
Interest expense
|
89,711
|
|
|
63,720
|
|
|
45,849
|
|
|||
|
Interest income
|
(67
|
)
|
|
(220
|
)
|
|
(466
|
)
|
|||
|
Income tax expense (benefit)
|
107,676
|
|
|
(29,268
|
)
|
|
123,585
|
|
|||
|
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
822,872
|
|
|
727,877
|
|
|
511,103
|
|
|||
|
Exploration
|
65,888
|
|
|
81,809
|
|
|
46,776
|
|
|||
|
Impairment of proved properties
|
172,641
|
|
|
208,923
|
|
|
219,037
|
|
|||
|
Abandonment and impairment of unproved properties
|
46,105
|
|
|
16,342
|
|
|
7,367
|
|
|||
|
Stock-based compensation expense
(1)
|
32,347
|
|
|
30,185
|
|
|
26,824
|
|
|||
|
Derivative gain
|
(3,080
|
)
|
|
(55,630
|
)
|
|
(37,086
|
)
|
|||
|
Derivative cash settlement gain (loss)
|
22,062
|
|
|
44,264
|
|
|
(25,671
|
)
|
|||
|
Change in Net Profits Plan liability
|
(21,842
|
)
|
|
(28,904
|
)
|
|
(25,477
|
)
|
|||
|
(Gain) loss on divestiture activity
|
(27,974
|
)
|
|
27,018
|
|
|
(220,676
|
)
|
|||
EBITDAX (Non-GAAP)
|
1,477,274
|
|
|
1,031,867
|
|
|
886,581
|
|
||||
|
Interest expense
|
(89,711
|
)
|
|
(63,720
|
)
|
|
(45,849
|
)
|
|||
|
Interest income
|
67
|
|
|
220
|
|
|
466
|
|
|||
|
Income tax (expense) benefit
|
(107,676
|
)
|
|
29,268
|
|
|
(123,585
|
)
|
|||
|
Exploration
|
(65,888
|
)
|
|
(81,809
|
)
|
|
(46,776
|
)
|
|||
|
Exploratory dry hole expense
|
5,846
|
|
|
20,861
|
|
|
277
|
|
|||
|
Amortization of debt discount and deferred financing costs
|
5,390
|
|
|
6,769
|
|
|
18,299
|
|
|||
|
Deferred income taxes
|
105,555
|
|
|
(29,638
|
)
|
|
123,789
|
|
|||
|
Plugging and abandonment
|
(9,946
|
)
|
|
(2,856
|
)
|
|
(5,849
|
)
|
|||
|
Other
|
2,775
|
|
|
527
|
|
|
(6,027
|
)
|
|||
|
Changes in current assets and liabilities
|
14,828
|
|
|
10,480
|
|
|
(40,794
|
)
|
|||
Net cash provided by operating activities (GAAP)
|
$
|
1,338,514
|
|
|
$
|
921,969
|
|
|
$
|
760,532
|
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
282,248
|
|
|
$
|
5,926
|
|
Accounts receivable (note 2)
|
318,371
|
|
|
254,805
|
|
||
Refundable income taxes
|
4,630
|
|
|
3,364
|
|
||
Prepaid expenses and other
|
9,944
|
|
|
30,017
|
|
||
Derivative asset
|
21,559
|
|
|
37,873
|
|
||
Deferred income taxes
|
10,749
|
|
|
8,579
|
|
||
Total current assets
|
647,501
|
|
|
340,564
|
|
||
|
|
|
|
||||
Property and equipment (successful efforts method):
|
|
|
|
||||
Land
|
1,857
|
|
|
1,845
|
|
||
Proved oil and gas properties
|
5,637,462
|
|
|
5,401,684
|
|
||
Less - accumulated depletion, depreciation, and amortization
|
(2,583,698
|
)
|
|
(2,376,170
|
)
|
||
Unproved oil and gas properties
|
271,100
|
|
|
175,287
|
|
||
Wells in progress
|
279,654
|
|
|
273,928
|
|
||
Materials inventory, at lower of cost or market
|
15,950
|
|
|
13,444
|
|
||
Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $7,390 in 2013 and $20,676 in 2012
|
19,072
|
|
|
33,620
|
|
||
Other property and equipment, net of accumulated depreciation of $28,775 in 2013 and $22,442 in 2012
|
218,395
|
|
|
153,559
|
|
||
Total property and equipment, net
|
3,859,792
|
|
|
3,677,197
|
|
||
|
|
|
|
||||
Noncurrent assets:
|
|
|
|
||||
Derivative asset
|
30,951
|
|
|
16,466
|
|
||
Restricted cash
|
96,713
|
|
|
86,773
|
|
||
Other noncurrent assets
|
70,208
|
|
|
78,529
|
|
||
Total other noncurrent assets
|
197,872
|
|
|
181,768
|
|
||
Total Assets
|
$
|
4,705,165
|
|
|
$
|
4,199,529
|
|
|
|
|
|
||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses (note 2)
|
$
|
606,751
|
|
|
$
|
525,627
|
|
Derivative liability
|
26,380
|
|
|
8,999
|
|
||
Other current liabilities
|
6,000
|
|
|
6,920
|
|
||
Total current liabilities
|
639,131
|
|
|
541,546
|
|
||
|
|
|
|
||||
Noncurrent liabilities:
|
|
|
|
||||
Revolving credit facility
|
—
|
|
|
340,000
|
|
||
Senior Notes (note 5)
|
1,600,000
|
|
|
1,100,000
|
|
||
Asset retirement obligation
|
115,659
|
|
|
112,912
|
|
||
Asset retirement obligation associated with oil and gas properties held for sale
|
3,033
|
|
|
1,393
|
|
||
Net Profits Plan liability
|
56,985
|
|
|
78,827
|
|
||
Deferred income taxes
|
650,125
|
|
|
537,383
|
|
||
Derivative liability
|
4,640
|
|
|
6,645
|
|
||
Other noncurrent liabilities
|
28,771
|
|
|
66,357
|
|
||
Total noncurrent liabilities
|
2,459,213
|
|
|
2,243,517
|
|
||
|
|
|
|
||||
Commitments and contingencies (note 6)
|
|
|
|
||||
|
|
|
|
||||
Stockholders' equity:
|
|
|
|
||||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 67,078,853 shares in 2013 and 66,245,816 shares in 2012; outstanding, net of treasury shares: 67,056,441 shares in 2013 and 66,195,235 shares in 2012
|
671
|
|
|
662
|
|
||
Additional paid-in capital
|
257,720
|
|
|
233,642
|
|
||
Treasury stock, at cost: 22,412 shares in 2013 and 50,581 shares in 2012
|
(823
|
)
|
|
(1,221
|
)
|
||
Retained earnings
|
1,354,669
|
|
|
1,190,397
|
|
||
Accumulated other comprehensive loss
|
(5,416
|
)
|
|
(9,014
|
)
|
||
Total stockholders' equity
|
1,606,821
|
|
|
1,414,466
|
|
||
Total Liabilities and Stockholders' Equity
|
$
|
4,705,165
|
|
|
$
|
4,199,529
|
|
|
For the Years
Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Operating revenues:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production revenue
|
$
|
2,199,550
|
|
|
$
|
1,473,868
|
|
|
$
|
1,332,392
|
|
Realized hedge (loss) gain
|
(1,777
|
)
|
|
3,866
|
|
|
(20,707
|
)
|
|||
Gain (loss) on divestiture activity
|
27,974
|
|
|
(27,018
|
)
|
|
220,676
|
|
|||
Marketed gas system revenue
|
60,039
|
|
|
52,808
|
|
|
69,898
|
|
|||
Other operating revenues
|
7,588
|
|
|
1,578
|
|
|
1,059
|
|
|||
Total operating revenues and other income
|
2,293,374
|
|
|
1,505,102
|
|
|
1,603,318
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production expense
|
597,045
|
|
|
391,872
|
|
|
290,111
|
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
822,872
|
|
|
727,877
|
|
|
511,103
|
|
|||
Exploration
|
74,104
|
|
|
90,248
|
|
|
53,537
|
|
|||
Impairment of proved properties
|
172,641
|
|
|
208,923
|
|
|
219,037
|
|
|||
Abandonment and impairment of unproved properties
|
46,105
|
|
|
16,342
|
|
|
7,367
|
|
|||
General and administrative
|
149,551
|
|
|
119,815
|
|
|
118,526
|
|
|||
Change in Net Profits Plan liability
|
(21,842
|
)
|
|
(28,904
|
)
|
|
(25,477
|
)
|
|||
Derivative gain
|
(3,080
|
)
|
|
(55,630
|
)
|
|
(37,086
|
)
|
|||
Marketed gas system expense
|
57,647
|
|
|
47,583
|
|
|
64,249
|
|
|||
Other operating expenses
|
30,076
|
|
|
6,993
|
|
|
17,567
|
|
|||
Total operating expenses
|
1,925,119
|
|
|
1,525,119
|
|
|
1,218,934
|
|
|||
Income (loss) from operations
|
368,255
|
|
|
(20,017
|
)
|
|
384,384
|
|
|||
Nonoperating income (expense):
|
|
|
|
|
|
||||||
Interest income
|
67
|
|
|
220
|
|
|
466
|
|
|||
Interest expense
|
(89,711
|
)
|
|
(63,720
|
)
|
|
(45,849
|
)
|
|||
Income (loss) before income taxes
|
278,611
|
|
|
(83,517
|
)
|
|
339,001
|
|
|||
Income tax (expense) benefit
|
(107,676
|
)
|
|
29,268
|
|
|
(123,585
|
)
|
|||
Net income (loss)
|
$
|
170,935
|
|
|
$
|
(54,249
|
)
|
|
$
|
215,416
|
|
Basic weighted-average common shares outstanding
|
66,615
|
|
|
65,138
|
|
|
63,755
|
|
|||
Diluted weighted-average common shares outstanding
|
67,998
|
|
|
65,138
|
|
|
67,564
|
|
|||
Basic net income (loss) per common share
|
$
|
2.57
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.38
|
|
Diluted net income (loss) per common share
|
$
|
2.51
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.19
|
|
|
For the Years
Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Net income (loss)
|
$
|
170,935
|
|
|
$
|
(54,249
|
)
|
|
$
|
215,416
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
||||||
Reclassification to earnings
(1)
|
1,115
|
|
|
(2,264
|
)
|
|
12,997
|
|
|||
Pension liability adjustment
(2)
|
2,483
|
|
|
(2,470
|
)
|
|
(1,795
|
)
|
|||
Total other comprehensive income (loss), net of tax
|
3,598
|
|
|
(4,734
|
)
|
|
11,202
|
|
|||
Total comprehensive income (loss)
|
$
|
174,533
|
|
|
$
|
(58,983
|
)
|
|
$
|
226,618
|
|
|
|
|
Additional Paid-in Capital
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Loss
|
|
Total Stockholders’ Equity
|
||||||||||||||||
|
Common Stock
|
|
|
Treasury Stock
|
|
Retained Earnings
|
|
|
|||||||||||||||||||||
|
Shares
|
|
Amount
|
|
|
Shares
|
|
Amount
|
|
|
|
||||||||||||||||||
Balances, January 1, 2011
|
63,412,800
|
|
|
$
|
634
|
|
|
$
|
191,674
|
|
|
(102,635
|
)
|
|
$
|
(423
|
)
|
|
$
|
1,042,123
|
|
|
$
|
(15,482
|
)
|
|
$
|
1,218,526
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
215,416
|
|
|
—
|
|
|
215,416
|
|
||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,202
|
|
|
11,202
|
|
||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,382
|
)
|
|
—
|
|
|
(6,382
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
41,358
|
|
|
—
|
|
|
2,300
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,300
|
|
||||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
|
278,773
|
|
|
3
|
|
|
(9,976
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9,973
|
)
|
||||||
Issuance of common stock upon stock option exercises
|
412,551
|
|
|
4
|
|
|
5,023
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,027
|
|
||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
27,945
|
|
|
21,568
|
|
|
(1,121
|
)
|
|
—
|
|
|
—
|
|
|
26,824
|
|
||||||
Balances, December 31, 2011
|
64,145,482
|
|
|
$
|
641
|
|
|
$
|
216,966
|
|
|
(81,067
|
)
|
|
$
|
(1,544
|
)
|
|
$
|
1,251,157
|
|
|
$
|
(4,280
|
)
|
|
$
|
1,462,940
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(54,249
|
)
|
|
—
|
|
|
(54,249
|
)
|
||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,734
|
)
|
|
(4,734
|
)
|
||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,511
|
)
|
|
—
|
|
|
(6,511
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
66,485
|
|
|
1
|
|
|
2,775
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,776
|
|
||||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
|
929,375
|
|
|
9
|
|
|
(21,631
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21,622
|
)
|
||||||
Issuance of common stock upon stock option exercises
|
240,368
|
|
|
2
|
|
|
3,038
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,040
|
|
||||||
Conversion of 3.50% Senior Convertible Notes to common stock, including income tax benefit of conversion
|
864,106
|
|
|
9
|
|
|
2,632
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,641
|
|
||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
29,862
|
|
|
30,486
|
|
|
323
|
|
|
—
|
|
|
—
|
|
|
30,185
|
|
||||||
Balances, December 31, 2012
|
66,245,816
|
|
|
$
|
662
|
|
|
$
|
233,642
|
|
|
(50,581
|
)
|
|
$
|
(1,221
|
)
|
|
$
|
1,190,397
|
|
|
$
|
(9,014
|
)
|
|
$
|
1,414,466
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
170,935
|
|
|
—
|
|
|
170,935
|
|
||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,598
|
|
|
3,598
|
|
||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,663
|
)
|
|
—
|
|
|
(6,663
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
77,427
|
|
|
1
|
|
|
3,671
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,672
|
|
||||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
|
526,852
|
|
|
5
|
|
|
(16,225
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16,220
|
)
|
||||||
Issuance of common stock upon stock option exercises
|
228,758
|
|
|
3
|
|
|
3,183
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,186
|
|
||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
31,949
|
|
|
28,169
|
|
|
398
|
|
|
—
|
|
|
—
|
|
|
32,347
|
|
||||||
Other income tax benefit
|
—
|
|
|
—
|
|
|
1,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,500
|
|
||||||
Balances, December 31, 2013
|
67,078,853
|
|
|
$
|
671
|
|
|
$
|
257,720
|
|
|
(22,412
|
)
|
|
$
|
(823
|
)
|
|
$
|
1,354,669
|
|
|
$
|
(5,416
|
)
|
|
$
|
1,606,821
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
170,935
|
|
|
$
|
(54,249
|
)
|
|
$
|
215,416
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
(Gain) loss on divestiture activity
|
(27,974
|
)
|
|
27,018
|
|
|
(220,676
|
)
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
822,872
|
|
|
727,877
|
|
|
511,103
|
|
|||
Exploratory dry hole expense
|
5,846
|
|
|
20,861
|
|
|
277
|
|
|||
Impairment of proved properties
|
172,641
|
|
|
208,923
|
|
|
219,037
|
|
|||
Abandonment and impairment of unproved properties
|
46,105
|
|
|
16,342
|
|
|
7,367
|
|
|||
Stock-based compensation expense
|
32,347
|
|
|
30,185
|
|
|
26,824
|
|
|||
Change in Net Profits Plan liability
|
(21,842
|
)
|
|
(28,904
|
)
|
|
(25,477
|
)
|
|||
Derivative gain
|
(3,080
|
)
|
|
(55,630
|
)
|
|
(37,086
|
)
|
|||
Derivative cash settlement gain (loss)
|
22,062
|
|
|
44,264
|
|
|
(25,671
|
)
|
|||
Amortization of debt discount and deferred financing costs
|
5,390
|
|
|
6,769
|
|
|
18,299
|
|
|||
Deferred income taxes
|
105,555
|
|
|
(29,638
|
)
|
|
123,789
|
|
|||
Plugging and abandonment
|
(9,946
|
)
|
|
(2,856
|
)
|
|
(5,849
|
)
|
|||
Other
|
2,775
|
|
|
527
|
|
|
(6,027
|
)
|
|||
Changes in current assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
(78,494
|
)
|
|
(21,389
|
)
|
|
(41,998
|
)
|
|||
Refundable income taxes
|
(1,266
|
)
|
|
2,217
|
|
|
2,901
|
|
|||
Prepaid expenses and other
|
1,364
|
|
|
(1,484
|
)
|
|
16,376
|
|
|||
Accounts payable and accrued expenses
|
93,224
|
|
|
31,136
|
|
|
(18,073
|
)
|
|||
Net cash provided by operating activities
|
1,338,514
|
|
|
921,969
|
|
|
760,532
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Net proceeds from sale of oil and gas properties
|
424,849
|
|
|
55,375
|
|
|
364,522
|
|
|||
Capital expenditures
|
(1,553,536
|
)
|
|
(1,507,828
|
)
|
|
(1,633,093
|
)
|
|||
Acquisition of proved and unproved oil and gas properties
|
(61,603
|
)
|
|
(5,773
|
)
|
|
—
|
|
|||
Receipts from restricted cash related to 1031 exchange
|
(1,754
|
)
|
|
—
|
|
|
—
|
|
|||
Other
|
(859
|
)
|
|
893
|
|
|
3,661
|
|
|||
Net cash used in investing activities
|
(1,192,903
|
)
|
|
(1,457,333
|
)
|
|
(1,264,910
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from credit facility
|
1,203,000
|
|
|
1,609,000
|
|
|
322,000
|
|
|||
Repayment of credit facility
|
(1,543,000
|
)
|
|
(1,269,000
|
)
|
|
(370,000
|
)
|
|||
Debt issuance costs related to credit facility
|
(3,444
|
)
|
|
—
|
|
|
(8,719
|
)
|
|||
Net proceeds from Senior Notes
|
490,185
|
|
|
392,138
|
|
|
684,242
|
|
|||
Repayment of 3.50% Senior Convertible Notes
|
—
|
|
|
(287,500
|
)
|
|
—
|
|
|||
Proceeds from sale of common stock
|
6,858
|
|
|
5,816
|
|
|
7,327
|
|
|||
Dividends paid
|
(6,663
|
)
|
|
(6,511
|
)
|
|
(6,382
|
)
|
|||
Net share settlement from issuance of stock awards
|
(16,220
|
)
|
|
(21,622
|
)
|
|
(9,973
|
)
|
|||
Other
|
(5
|
)
|
|
(225
|
)
|
|
—
|
|
|||
Net cash provided by financing activities
|
130,711
|
|
|
422,096
|
|
|
618,495
|
|
|||
|
|
|
|
|
|
||||||
Net change in cash and cash equivalents
|
276,322
|
|
|
(113,268
|
)
|
|
114,117
|
|
|||
Cash and cash equivalents at beginning of period
|
5,926
|
|
|
119,194
|
|
|
5,077
|
|
|||
Cash and cash equivalents at end of period
|
$
|
282,248
|
|
|
$
|
5,926
|
|
|
$
|
119,194
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Cash paid for interest, net of capitalized interest
|
$
|
(70,702
|
)
|
|
$
|
(51,328
|
)
|
|
$
|
(22,133
|
)
|
|
|
|
|
|
|
||||||
Net cash refunded for income taxes
|
$
|
204
|
|
|
$
|
1,389
|
|
|
$
|
4,046
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands, except per share amounts)
|
||||||||||
Net income (loss)
|
$
|
170,935
|
|
|
$
|
(54,249
|
)
|
|
$
|
215,416
|
|
Basic weighted-average common shares outstanding
|
66,615
|
|
|
65,138
|
|
|
63,755
|
|
|||
Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs
|
1,383
|
|
|
—
|
|
|
2,592
|
|
|||
Add: dilutive effect of 3.50% Senior Convertible Notes
|
—
|
|
|
—
|
|
|
1,217
|
|
|||
Diluted weighted-average common shares outstanding
|
67,998
|
|
|
65,138
|
|
|
67,564
|
|
|||
Basic net income (loss) per common share
|
$
|
2.57
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.38
|
|
Diluted net income (loss) per common share
|
$
|
2.51
|
|
|
$
|
(0.83
|
)
|
|
$
|
3.19
|
|
|
Derivative Reclassification to Earnings
|
|
Pension Liability Adjustments
|
||||
|
(in thousands)
|
||||||
For the year ended December 31, 2011
|
|
|
|
||||
Before tax income (loss)
|
$
|
20,707
|
|
|
$
|
(2,779
|
)
|
Tax benefit (expense)
|
(7,710
|
)
|
|
984
|
|
||
Income (loss), net of tax
|
$
|
12,997
|
|
|
$
|
(1,795
|
)
|
For the year ended December 31, 2012
|
|
|
|
||||
Before tax loss
|
$
|
(3,865
|
)
|
|
$
|
(3,909
|
)
|
Tax benefit
|
1,601
|
|
|
1,439
|
|
||
Loss, net of tax
|
$
|
(2,264
|
)
|
|
$
|
(2,470
|
)
|
For the year ended December 31, 2013
|
|
|
|
||||
Before tax income
|
$
|
1,777
|
|
|
$
|
4,005
|
|
Tax expense
|
(662
|
)
|
|
(1,522
|
)
|
||
Income, net of tax
|
$
|
1,115
|
|
|
$
|
2,483
|
|
|
As of December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in thousands)
|
||||||
Accrued oil, gas, and NGL production revenue
|
$
|
228,169
|
|
|
$
|
160,568
|
|
Amounts due from joint interest owners
|
37,517
|
|
|
42,740
|
|
||
Acquisition and Development Agreement receivable
|
—
|
|
|
19,931
|
|
||
State severance tax refunds
|
29,213
|
|
|
17,237
|
|
||
Other
|
23,472
|
|
|
14,329
|
|
||
Total accounts receivable
|
$
|
318,371
|
|
|
$
|
254,805
|
|
|
As of December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in thousands)
|
||||||
Accrued capital expenditures
|
$
|
217,820
|
|
|
$
|
243,611
|
|
Revenue and severance tax payable
|
87,852
|
|
|
65,494
|
|
||
Accrued lease operating expense
|
29,296
|
|
|
28,037
|
|
||
Accrued property taxes
|
10,401
|
|
|
9,478
|
|
||
Joint owner advances
|
96,636
|
|
|
69,639
|
|
||
Accrued compensation
|
71,466
|
|
|
35,607
|
|
||
Accrued interest
|
40,027
|
|
|
25,027
|
|
||
Other
|
53,253
|
|
|
48,734
|
|
||
Total accounts payable and accrued expenses
|
$
|
606,751
|
|
|
$
|
525,627
|
|
•
|
Mid-Continent Divestitures.
In December 2013, the Company divested of certain non-strategic assets located in its Mid-Continent region, with the largest transaction being the sale of the Company’s Anadarko Basin assets. Total cash proceeds received at closing (referred throughout this report as “divestiture proceeds”) were
$370.3 million
. The estimated net gain on these divestitures is
$29.2 million
. These divestitures are subject to normal post-closing adjustments and are expected to be finalized during the first half of 2014. A portion of one transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”).
|
•
|
Rocky Mountain Divestitures
. During 2013, the Company divested of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were
$56.3 million
. The estimated net gain on these divestitures is
$10.1 million
. These divestitures are subject to normal post-closing adjustments and are expected to be finalized during the first half of 2014.
|
•
|
Permian Divestiture
. In December 2013, the Company divested of certain non-strategic assets located in its Permian region. Total divestiture proceeds were
$14.5 million
. The estimated net loss on this divestiture is
$6.5 million
. This divestiture is subject to normal post-closing adjustments and is expected to be finalized during the first half of 2014.
|
•
|
Eagle Ford Shale Divestiture.
In August 2011, the Company divested of certain operated Eagle Ford shale assets located in its South Texas & Gulf Coast region. This divestiture was comprised of the Company’s entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of its operated acreage in Dimmit County, Texas. Total divestiture proceeds were
$230.7 million
. The final gain on this divestiture was
$193.8 million
. Please refer to
Note 12 - Acquisition and Development Agreement
for information on additional Eagle Ford activity in 2011.
|
•
|
Mid-Continent Divestiture.
In June 2011, the Company divested of certain non-strategic assets located in its Mid-Continent region. Total divestiture proceeds were
$35.8 million
. The final gain on this divestiture was
$28.5 million
.
|
•
|
Rocky Mountain Divestiture.
In January 2011, the Company divested of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were
$45.5 million
. The final gain on this divestiture was
$27.2 million
.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
|
|
(in thousands)
|
||||||||||
Current portion of income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,757
|
)
|
State
|
|
2,121
|
|
|
370
|
|
|
1,553
|
|
|||
Deferred portion of income tax expense (benefit)
|
|
105,555
|
|
|
(29,638
|
)
|
|
123,789
|
|
|||
Total income tax expense (benefit)
|
|
$
|
107,676
|
|
|
$
|
(29,268
|
)
|
|
$
|
123,585
|
|
Effective tax rate
|
|
38.6
|
%
|
|
35.0
|
%
|
|
36.5
|
%
|
|
|
As of December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
|
|
(in thousands)
|
||||||
Deferred tax liabilities:
|
|
|
|
|
||||
Oil and gas properties
|
|
$
|
768,463
|
|
|
$
|
678,624
|
|
Derivative asset
|
|
9,529
|
|
|
15,942
|
|
||
Other
|
|
1,245
|
|
|
6,443
|
|
||
Total deferred tax liabilities
|
|
779,237
|
|
|
701,009
|
|
||
Deferred tax assets:
|
|
|
|
|
|
|
||
Federal and state tax net operating loss carryovers
|
|
91,788
|
|
|
113,522
|
|
||
Net Profits Plan liability
|
|
20,913
|
|
|
29,233
|
|
||
Stock compensation
|
|
18,820
|
|
|
18,026
|
|
||
Other long-term liabilities
|
|
13,341
|
|
|
16,739
|
|
||
Total deferred tax assets
|
|
144,862
|
|
|
177,520
|
|
||
Valuation allowance
|
|
(5,001
|
)
|
|
(5,315
|
)
|
||
Net deferred tax assets
|
|
139,861
|
|
|
172,205
|
|
||
Total net deferred tax liabilities
|
|
639,376
|
|
|
528,804
|
|
||
Less: current deferred income tax liabilities
|
|
(172
|
)
|
|
(5,442
|
)
|
||
Add: current deferred income tax assets
|
|
10,921
|
|
|
14,021
|
|
||
Non-current net deferred tax liabilities
|
|
$
|
650,125
|
|
|
$
|
537,383
|
|
Current federal income tax refundable
|
|
$
|
4,630
|
|
|
$
|
2,511
|
|
Current state income tax refundable
|
|
$
|
—
|
|
|
$
|
853
|
|
Current state income tax payable
|
|
$
|
1,460
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Federal statutory tax expense (benefit)
|
$
|
97,514
|
|
|
$
|
(29,231
|
)
|
|
$
|
118,652
|
|
Increase (decrease) in tax resulting from:
|
|
|
|
|
|
||||||
State tax expense (benefit) (net of federal benefit)
|
9,400
|
|
|
(992
|
)
|
|
6,458
|
|
|||
Research and development credit
|
—
|
|
|
(970
|
)
|
|
(4,516
|
)
|
|||
Change in valuation allowance
|
(314
|
)
|
|
1,524
|
|
|
1,627
|
|
|||
Statutory depletion
|
(154
|
)
|
|
(210
|
)
|
|
(341
|
)
|
|||
Other
|
1,230
|
|
|
611
|
|
|
1,705
|
|
|||
Income tax expense (benefit)
|
$
|
107,676
|
|
|
$
|
(29,268
|
)
|
|
$
|
123,585
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
2,278
|
|
|
$
|
1,961
|
|
|
$
|
807
|
|
Additions based on tax positions related to current year
|
—
|
|
|
—
|
|
|
1,172
|
|
|||
Additions for tax positions of prior years
|
80
|
|
|
317
|
|
|
183
|
|
|||
Reductions for lapse of statute of limitations
|
—
|
|
|
—
|
|
|
(201
|
)
|
|||
Ending balance
|
$
|
2,358
|
|
|
$
|
2,278
|
|
|
$
|
1,961
|
|
Borrowing Base Utilization Percentage
|
|
<25%
|
|
≥25% <50%
|
|
≥50% <75%
|
|
≥75% <90%
|
|
≥90%
|
|||||
Eurodollar Loans
|
|
1.500
|
%
|
|
1.750
|
%
|
|
2.000
|
%
|
|
2.250
|
%
|
|
2.500
|
%
|
ABR Loans or Swingline Loans
|
|
0.500
|
%
|
|
0.750
|
%
|
|
1.000
|
%
|
|
1.250
|
%
|
|
1.500
|
%
|
Commitment Fee Rate
|
|
0.375
|
%
|
|
0.375
|
%
|
|
0.500
|
%
|
|
0.500
|
%
|
|
0.500
|
%
|
|
As of February 12, 2014
|
|
As of December 31, 2013
|
|
As of December 31, 2012
|
||||||
|
(in millions)
|
||||||||||
Credit facility balance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
340.0
|
|
Letters of credit
(1)
|
$
|
0.8
|
|
|
$
|
0.8
|
|
|
$
|
0.8
|
|
Available borrowing capacity
|
$
|
1,299.2
|
|
|
$
|
1,299.2
|
|
|
$
|
659.2
|
|
|
As of December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in thousands)
|
||||||
6.625% Senior Notes due 2019
|
$
|
350,000
|
|
|
$
|
350,000
|
|
6.50% Senior Notes due 2021
|
350,000
|
|
|
350,000
|
|
||
6.50% Senior Notes due 2023
|
400,000
|
|
|
400,000
|
|
||
5.0% Senior Notes due 2024
|
500,000
|
|
|
—
|
|
||
Total long-term debt
|
$
|
1,600,000
|
|
|
$
|
1,100,000
|
|
2015
|
103.313
|
%
|
2016
|
101.656
|
%
|
2017 and thereafter
|
100.000
|
%
|
Years Ending December 31,
|
|
(in thousands)
|
||
2014
|
|
$
|
179,118
|
|
2015
|
|
147,119
|
|
|
2016
|
|
144,438
|
|
|
2017
|
|
132,559
|
|
|
2018
|
|
128,418
|
|
|
Thereafter
|
|
481,947
|
|
|
Total
|
|
$
|
1,213,599
|
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|||||||||||||||
|
PSUs
|
|
Weighted-Average Grant-Date Fair Value
|
|
PSUs
|
|
Weighted-Average Grant-Date Fair Value
|
|
PSUs
|
|
Weighted-Average Grant-Date Fair Value
|
|||||||||
Non-vested at beginning of year
(1)
|
669,308
|
|
|
$
|
63.91
|
|
|
885,894
|
|
|
$
|
57.52
|
|
|
1,110,666
|
|
|
$
|
39.48
|
|
Granted
(1)
|
274,831
|
|
|
$
|
64.13
|
|
|
314,853
|
|
|
$
|
51.98
|
|
|
266,282
|
|
|
$
|
91.45
|
|
Vested
(1)
|
(345,005
|
)
|
|
$
|
60.06
|
|
|
(493,679
|
)
|
|
$
|
44.72
|
|
|
(364,172
|
)
|
|
$
|
35.74
|
|
Forfeited
(1)
|
(26,665
|
)
|
|
$
|
69.74
|
|
|
(37,760
|
)
|
|
$
|
65.35
|
|
|
(126,882
|
)
|
|
$
|
33.32
|
|
Non-vested at end of year
(1)
|
572,469
|
|
|
$
|
66.07
|
|
|
669,308
|
|
|
$
|
63.91
|
|
|
885,894
|
|
|
$
|
57.52
|
|
(1)
|
The number of awards assumes a
one
multiplier. The final number of shares of common stock issued may vary depending on the ending
three
-year performance multiplier, which ranges from
zero
to
two
.
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|||||||||||||||
|
RSUs
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
RSUs
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
RSUs
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|||||||||
Non-vested at beginning of year
|
496,244
|
|
|
$
|
51.81
|
|
|
308,877
|
|
|
$
|
44.33
|
|
|
333,359
|
|
|
$
|
31.16
|
|
Granted
|
329,939
|
|
|
$
|
60.01
|
|
|
379,332
|
|
|
$
|
49.47
|
|
|
98,952
|
|
|
$
|
72.69
|
|
Vested
|
(207,376
|
)
|
|
$
|
49.73
|
|
|
(166,672
|
)
|
|
$
|
32.72
|
|
|
(105,820
|
)
|
|
$
|
30.61
|
|
Forfeited
|
(38,376
|
)
|
|
$
|
54.37
|
|
|
(25,293
|
)
|
|
$
|
51.06
|
|
|
(17,614
|
)
|
|
$
|
36.80
|
|
Non-vested at end of year
|
580,431
|
|
|
$
|
57.05
|
|
|
496,244
|
|
|
$
|
51.81
|
|
|
308,877
|
|
|
$
|
44.33
|
|
|
|
|
Weighted -
|
|
|
|||||
|
|
|
Average
|
|
Aggregate
|
|||||
|
|
|
Exercise
|
|
Intrinsic
|
|||||
|
Shares
|
|
Price
|
|
Value
|
|||||
For the year ended December 31, 2011
|
|
|
|
|
|
|||||
Outstanding, start of year
|
920,765
|
|
|
$
|
13.11
|
|
|
|
||
Exercised
|
(412,551
|
)
|
|
$
|
12.19
|
|
|
$
|
24,359,240
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
|
||
Outstanding, end of year
|
508,214
|
|
|
$
|
13.86
|
|
|
$
|
30,109,110
|
|
Vested and exercisable at end of year
|
508,214
|
|
|
$
|
13.86
|
|
|
$
|
30,109,110
|
|
For the year ended December 31, 2012
|
|
|
|
|
|
|||||
Outstanding, start of year
|
508,214
|
|
|
$
|
13.86
|
|
|
|
||
Exercised
|
(240,368
|
)
|
|
$
|
12.65
|
|
|
$
|
11,842,575
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
|
||
Outstanding, end of year
|
267,846
|
|
|
$
|
14.95
|
|
|
$
|
9,983,177
|
|
Vested and exercisable at end of year
|
267,846
|
|
|
$
|
14.95
|
|
|
$
|
9,983,177
|
|
For the year ended December 31, 2013
|
|
|
|
|
|
|||||
Outstanding, start of year
|
267,846
|
|
|
$
|
14.95
|
|
|
|
||
Exercised
|
(228,758
|
)
|
|
$
|
13.92
|
|
|
$
|
12,326,994
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
|
||
Outstanding, end of year
|
39,088
|
|
|
$
|
20.87
|
|
|
$
|
2,432,837
|
|
Vested and exercisable at end of year
|
39,088
|
|
|
$
|
20.87
|
|
|
$
|
2,432,837
|
|
|
For the Years Ended December 31,
|
|||||||
|
2013
|
|
2012
|
|
2011
|
|||
Risk free interest rate
|
0.1
|
%
|
|
0.1
|
%
|
|
0.2
|
%
|
Dividend yield
|
0.2
|
%
|
|
0.2
|
%
|
|
0.2
|
%
|
Volatility factor of the expected market
|
|
|
|
|
|
|||
price of the Company’s common stock
|
41.1
|
%
|
|
47.8
|
%
|
|
36.3
|
%
|
Expected life (in years)
|
0.5
|
|
|
0.5
|
|
|
0.5
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
General and administrative expense
|
$
|
13,734
|
|
|
$
|
15,565
|
|
|
$
|
19,326
|
|
Exploration expense
|
1,310
|
|
|
1,751
|
|
|
2,091
|
|
|||
Total
|
$
|
15,044
|
|
|
$
|
17,316
|
|
|
$
|
21,417
|
|
|
For the Years Ended December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in thousands)
|
||||||
Change in benefit obligation:
|
|
|
|
||||
Projected benefit obligation at beginning of year
|
$
|
40,237
|
|
|
$
|
29,480
|
|
Service cost
|
6,291
|
|
|
4,934
|
|
||
Interest cost
|
1,627
|
|
|
1,374
|
|
||
Plan amendments
|
—
|
|
|
—
|
|
||
Actuarial loss (gain)
|
(1,577
|
)
|
|
5,467
|
|
||
Benefits paid
|
(3,293
|
)
|
|
(1,018
|
)
|
||
Projected benefit obligation at end of year
|
43,285
|
|
|
40,237
|
|
||
|
|
|
|
||||
Change in plan assets:
|
|
|
|
||||
Fair value of plan assets at beginning of year
|
20,254
|
|
|
13,940
|
|
||
Actual return on plan assets
|
2,726
|
|
|
1,952
|
|
||
Employer contribution
|
4,971
|
|
|
5,380
|
|
||
Benefits paid
|
(3,293
|
)
|
|
(1,018
|
)
|
||
Fair value of plan assets at end of year
|
24,658
|
|
|
20,254
|
|
||
Funded status at end of year
|
$
|
(18,627
|
)
|
|
$
|
(19,983
|
)
|
|
As of December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in thousands)
|
||||||
Projected benefit obligation
|
$
|
43,285
|
|
|
$
|
40,237
|
|
|
|
|
|
||||
Accumulated benefit obligation
|
$
|
32,396
|
|
|
$
|
29,437
|
|
Less: Fair value of plan assets
|
(24,658
|
)
|
|
(20,254
|
)
|
||
Underfunded accumulated benefit obligation
|
$
|
7,738
|
|
|
$
|
9,183
|
|
|
As of December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in thousands)
|
||||||
Unrecognized actuarial losses
|
$
|
8,439
|
|
|
$
|
12,427
|
|
Unrecognized prior service costs
|
136
|
|
|
153
|
|
||
Unrecognized transition obligation
|
—
|
|
|
—
|
|
||
Accumulated other comprehensive loss
|
$
|
8,575
|
|
|
$
|
12,580
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Net actuarial gain (loss)
|
$
|
2,766
|
|
|
$
|
(4,680
|
)
|
|
$
|
(3,014
|
)
|
Prior service cost
|
—
|
|
|
—
|
|
|
(170
|
)
|
|||
Less: Amortization of:
|
|
|
|
|
|
||||||
Prior service cost
|
(17
|
)
|
|
(17
|
)
|
|
—
|
|
|||
Actuarial loss
|
(1,222
|
)
|
|
(754
|
)
|
|
(405
|
)
|
|||
Total other comprehensive income (loss)
|
$
|
4,005
|
|
|
$
|
(3,909
|
)
|
|
$
|
(2,779
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
||||||
Service cost
|
$
|
6,291
|
|
|
$
|
4,934
|
|
|
$
|
3,800
|
|
Interest cost
|
1,627
|
|
|
1,374
|
|
|
1,184
|
|
|||
Expected return on plan assets that reduces periodic pension cost
|
(1,538
|
)
|
|
(1,165
|
)
|
|
(880
|
)
|
|||
Amortization of prior service cost
|
17
|
|
|
17
|
|
|
—
|
|
|||
Amortization of net actuarial loss
|
1,222
|
|
|
754
|
|
|
405
|
|
|||
Net periodic benefit cost
|
$
|
7,619
|
|
|
$
|
5,914
|
|
|
$
|
4,509
|
|
|
As of December 31,
|
||||
|
2013
|
|
2012
|
|
2011
|
Projected benefit obligation
|
|
|
|
|
|
Discount rate
|
5.0%
|
|
3.9%
|
|
4.7%
|
Rate of compensation increase
|
6.2%
|
|
6.2%
|
|
6.2%
|
Net periodic benefit cost
|
|
|
|
|
|
Discount rate
|
3.9%
|
|
4.7%
|
|
5.3%
|
Expected return on plan assets
|
7.5%
|
|
7.5%
|
|
7.5%
|
Rate of compensation increase
|
6.2%
|
|
6.2%
|
|
6.2%
|
|
Target
|
|
As of December 31,
|
|||||
Asset Category
|
2014
|
|
2013
|
|
2012
|
|||
Equity securities
|
44.0
|
%
|
|
43.6
|
%
|
|
42.7
|
%
|
Debt securities
|
33.0
|
%
|
|
32.2
|
%
|
|
32.8
|
%
|
Other
|
23.0
|
%
|
|
24.2
|
%
|
|
24.5
|
%
|
Total
|
100.0
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
|
|
|
|
|
Fair Value Measurements Using:
|
|||||||||||||
|
Actual Asset Allocation
|
|
Total
|
|
Level 1 Inputs
|
|
Level 2 Inputs
|
|
Level 3 Inputs
|
|||||||||
|
|
|
(in thousands)
|
|||||||||||||||
Cash
|
—
|
%
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Domestic
(1)
|
29.9
|
%
|
|
7,371
|
|
|
4,888
|
|
|
2,483
|
|
|
—
|
|
||||
International
(2)
|
13.7
|
%
|
|
3,373
|
|
|
3,373
|
|
|
—
|
|
|
—
|
|
||||
Total Equity Securities
|
43.6
|
%
|
|
10,744
|
|
|
8,261
|
|
|
2,483
|
|
|
—
|
|
||||
Fixed Income Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
High-Yield Bonds
(3)
|
5.9
|
%
|
|
1,448
|
|
|
1,448
|
|
|
—
|
|
|
—
|
|
||||
Core Fixed Income
(4)
|
20.3
|
%
|
|
5,006
|
|
|
5,006
|
|
|
—
|
|
|
—
|
|
||||
Floating Rate Corp Loans
(5)
|
6.0
|
%
|
|
1,483
|
|
|
1,483
|
|
|
—
|
|
|
—
|
|
||||
Total Fixed Income Securities
|
32.2
|
%
|
|
7,937
|
|
|
7,937
|
|
|
—
|
|
|
—
|
|
||||
Other Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Commodities
(6)
|
3.8
|
%
|
|
945
|
|
|
945
|
|
|
—
|
|
|
—
|
|
||||
Real Estate
(7)
|
3.5
|
%
|
|
859
|
|
|
—
|
|
|
—
|
|
|
859
|
|
||||
Hedge Fund
(8)
|
14.3
|
%
|
|
3,517
|
|
|
955
|
|
|
—
|
|
|
2,562
|
|
||||
Collective Investment Trusts
(9)
|
2.6
|
%
|
|
656
|
|
|
—
|
|
|
656
|
|
|
—
|
|
||||
Total Other Securities
|
24.2
|
%
|
|
5,977
|
|
|
1,900
|
|
|
656
|
|
|
3,421
|
|
||||
Total Investments
|
100.0
|
%
|
|
$
|
24,658
|
|
|
$
|
18,098
|
|
|
$
|
3,139
|
|
|
$
|
3,421
|
|
(1)
|
Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of this fund is to approximate the S&P 500 by investing in one or more collective investment funds.
|
(2)
|
International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations.
|
(3)
|
High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis.
|
(4)
|
The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay's Capital Aggregate Bond Index with a modest amount of variability in duration around the index.
|
(5)
|
Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates.
|
(6)
|
Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities.
|
(7)
|
The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity.
|
(8)
|
The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.
|
(9)
|
Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities.
|
December 31, 2012
|
$
|
2,384
|
|
Purchases
|
742
|
|
|
Realized gain on assets
|
161
|
|
|
Unrealized gain on assets
|
134
|
|
|
December 31, 2013
|
$
|
3,421
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|||||||||||||
|
Actual Asset Allocation
|
|
Total
|
|
Level 1 Inputs
|
|
Level 2 Inputs
|
|
Level 3 Inputs
|
|||||||||
|
|
|
(in thousands)
|
|||||||||||||||
Cash and Money Market Funds
|
3.8
|
%
|
|
$
|
778
|
|
|
$
|
778
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Domestic
(1)
|
29.2
|
%
|
|
5,920
|
|
|
5,920
|
|
|
—
|
|
|
—
|
|
||||
International
(2)
|
13.5
|
%
|
|
2,740
|
|
|
2,740
|
|
|
—
|
|
|
—
|
|
||||
Total Equity Securities
|
42.7
|
%
|
|
8,660
|
|
|
8,660
|
|
|
—
|
|
|
—
|
|
||||
Fixed Income Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
High-Yield Bonds
(3)
|
6.1
|
%
|
|
1,240
|
|
|
1,240
|
|
|
—
|
|
|
—
|
|
||||
Core Fixed Income
(4)
|
20.8
|
%
|
|
4,204
|
|
|
4,204
|
|
|
—
|
|
|
—
|
|
||||
Floating Rate Corp Loans
(5)
|
5.9
|
%
|
|
1,186
|
|
|
1,186
|
|
|
—
|
|
|
—
|
|
||||
Total Fixed Income Securities
|
32.8
|
%
|
|
6,630
|
|
|
6,630
|
|
|
—
|
|
|
—
|
|
||||
Other Securities:
|
|
|
|
|
|
|
|
|
|
|||||||||
Commodities
(6)
|
3.3
|
%
|
|
669
|
|
|
669
|
|
|
—
|
|
|
—
|
|
||||
Real Estate
(7)
|
3.9
|
%
|
|
783
|
|
|
—
|
|
|
—
|
|
|
783
|
|
||||
Hedge Fund
(8)
|
13.5
|
%
|
|
2,734
|
|
|
1,133
|
|
|
—
|
|
|
1,601
|
|
||||
Total Other Securities
|
20.7
|
%
|
|
4,186
|
|
|
1,802
|
|
|
—
|
|
|
2,384
|
|
||||
Total Investments
|
100.0
|
%
|
|
$
|
20,254
|
|
|
$
|
17,870
|
|
|
$
|
—
|
|
|
$
|
2,384
|
|
(1)
|
Equity securities of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand.
|
(2)
|
International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations.
|
(3)
|
High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis.
|
(4)
|
The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay's Capital Aggregate Bond Index with a modest amount of variability in duration around the index.
|
(5)
|
Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates.
|
(6)
|
Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities.
|
(7)
|
The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity.
|
(8)
|
The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.
|
December 31, 2011
|
$
|
—
|
|
Purchases
|
2,329
|
|
|
Investment Returns
|
55
|
|
|
December 31, 2012
|
$
|
2,384
|
|
Years Ending December 31,
|
|
(in thousands)
|
||
2014
|
|
$
|
2,120
|
|
2015
|
|
$
|
2,837
|
|
2016
|
|
$
|
3,287
|
|
2017
|
|
$
|
3,993
|
|
2018
|
|
$
|
4,407
|
|
2019 through 2023
|
|
$
|
33,031
|
|
|
As of December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in thousands)
|
||||||
Beginning asset retirement obligation
|
$
|
120,518
|
|
|
$
|
95,906
|
|
Liabilities incurred
|
18,682
|
|
|
13,050
|
|
||
Liabilities settled
|
(33,129
|
)
|
|
(8,101
|
)
|
||
Accretion expense
|
5,997
|
|
|
4,679
|
|
||
Revision to estimated cash flows
|
9,118
|
|
|
14,984
|
|
||
Ending asset retirement obligation
|
$
|
121,186
|
|
|
$
|
120,518
|
|
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(Bbls)
|
|
(per Bbl)
|
|||
First quarter 2014
|
|
2,600,000
|
|
|
$
|
96.92
|
|
Second quarter 2014
|
|
2,373,000
|
|
|
$
|
94.95
|
|
Third quarter 2014
|
|
973,000
|
|
|
$
|
95.25
|
|
Fourth quarter 2014
|
|
891,000
|
|
|
$
|
95.16
|
|
2015
|
|
2,911,000
|
|
|
$
|
89.06
|
|
2016
|
|
2,704,000
|
|
|
$
|
85.19
|
|
All oil swaps*
|
|
12,452,000
|
|
|
|
Contract Period
|
|
NYMEX WTI
Volumes
|
|
Weighted-
Average
Floor
Price
|
|
Weighted-
Average
Ceiling
Price
|
|||||
|
|
(Bbls)
|
|
(per Bbl)
|
|
(per Bbl)
|
|||||
First quarter 2014
|
|
694,000
|
|
|
$
|
80.97
|
|
|
$
|
115.07
|
|
Second quarter 2014
|
|
431,000
|
|
|
$
|
85.00
|
|
|
$
|
102.50
|
|
Third quarter 2014
|
|
973,000
|
|
|
$
|
85.00
|
|
|
$
|
102.58
|
|
Fourth quarter 2014
|
|
923,000
|
|
|
$
|
85.00
|
|
|
$
|
102.63
|
|
2015
|
|
3,366,000
|
|
|
$
|
85.00
|
|
|
$
|
94.25
|
|
All oil collars
|
|
6,387,000
|
|
|
|
|
|
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(MMBtu)
|
|
(per MMBtu)
|
|||
First quarter 2014
|
|
33,651,000
|
|
|
$
|
4.25
|
|
Second quarter 2014
|
|
25,729,000
|
|
|
$
|
3.96
|
|
Third quarter 2014
|
|
26,398,000
|
|
|
$
|
4.01
|
|
Fourth quarter 2014
|
|
23,965,000
|
|
|
$
|
4.01
|
|
2015
|
|
63,317,000
|
|
|
$
|
4.03
|
|
2016
|
|
39,014,000
|
|
|
$
|
4.18
|
|
2017
|
|
23,430,000
|
|
|
$
|
4.21
|
|
2018
|
|
10,200,000
|
|
|
$
|
4.31
|
|
All gas swaps*
|
|
245,704,000
|
|
|
|
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Floor
Price
|
|
Weighted-
Average
Ceiling
Price
|
|||||
|
|
(MMBtu)
|
|
(per MMBtu)
|
|
(per MMBtu)
|
|||||
First quarter 2014
|
|
1,540,000
|
|
|
$
|
4.39
|
|
|
$
|
5.58
|
|
Second quarter 2014
|
|
4,194,000
|
|
|
$
|
4.38
|
|
|
$
|
5.29
|
|
2015
|
|
14,480,000
|
|
|
$
|
3.96
|
|
|
$
|
4.30
|
|
All gas collars*
|
|
20,214,000
|
|
|
|
|
|
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(Bbls)
|
|
(per Bbl)
|
|||
First quarter 2014
|
|
913,000
|
|
|
$
|
59.72
|
|
Second quarter 2014
|
|
565,000
|
|
|
$
|
63.22
|
|
Third quarter 2014
|
|
544,000
|
|
|
$
|
62.34
|
|
Fourth quarter 2014
|
|
527,000
|
|
|
$
|
61.57
|
|
All NGL swaps*
|
|
2,549,000
|
|
|
|
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(MMBtu)
|
|
(per MMBtu)
|
|||
First quarter 2014
|
|
261,000
|
|
|
$
|
4.39
|
|
Second quarter 2014
|
|
365,000
|
|
|
$
|
3.84
|
|
Third quarter 2014
|
|
341,000
|
|
|
$
|
3.89
|
|
Fourth quarter 2014
|
|
321,000
|
|
|
$
|
3.97
|
|
2015
|
|
1,133,000
|
|
|
$
|
3.72
|
|
2016
|
|
69,000
|
|
|
$
|
4.12
|
|
All gas swaps*
|
|
2,490,000
|
|
|
|
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(Bbls)
|
|
(per Bbl)
|
|||
First quarter 2014
|
|
516,000
|
|
|
$
|
54.85
|
|
Second quarter 2014
|
|
531,000
|
|
|
$
|
52.53
|
|
Third quarter 2014
|
|
416,000
|
|
|
$
|
52.47
|
|
Fourth quarter 2014
|
|
334,000
|
|
|
$
|
52.52
|
|
All NGL swaps*
|
|
1,797,000
|
|
|
|
|
As of December 31, 2013
|
||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
||||
|
(in thousands)
|
||||||||||
Commodity Contracts
|
Current assets
|
|
$
|
21,559
|
|
|
Current liabilities
|
|
$
|
26,380
|
|
Commodity Contracts
|
Noncurrent assets
|
|
30,951
|
|
|
Noncurrent liabilities
|
|
4,640
|
|
||
Derivatives not designated as hedging instruments
|
|
|
$
|
52,510
|
|
|
|
|
$
|
31,020
|
|
|
As of December 31, 2012
|
||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
||||
|
(in thousands)
|
||||||||||
Commodity Contracts
|
Current assets
|
|
$
|
37,873
|
|
|
Current liabilities
|
|
$
|
8,999
|
|
Commodity Contracts
|
Noncurrent assets
|
|
16,466
|
|
|
Noncurrent liabilities
|
|
6,645
|
|
||
Derivatives not designated as hedging instruments
|
|
|
$
|
54,339
|
|
|
|
|
$
|
15,644
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||
|
|
As of December 31,
|
|
As of December 31,
|
||||||||||||
Offsetting of Derivative Assets and Liabilities
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
|
|
(in thousands)
|
||||||||||||||
Gross amounts presented in the accompanying balance sheets
|
|
$
|
52,510
|
|
|
$
|
54,339
|
|
|
$
|
(31,020
|
)
|
|
$
|
(15,644
|
)
|
Amounts not offset in the accompanying balance sheets
|
|
(30,652
|
)
|
|
(13,400
|
)
|
|
30,652
|
|
|
13,400
|
|
||||
Net amounts
|
|
$
|
21,858
|
|
|
$
|
40,939
|
|
|
$
|
(368
|
)
|
|
$
|
(2,244
|
)
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Derivative cash settlement (gain) loss:
|
|
|
|
|
|
||||||
Oil contracts
|
$
|
15,161
|
|
|
$
|
11,893
|
|
|
$
|
22,633
|
|
Gas contracts
|
(30,338
|
)
|
|
(47,270
|
)
|
|
(10,711
|
)
|
|||
NGL contracts
|
(6,885
|
)
|
|
(8,887
|
)
|
|
13,749
|
|
|||
Total derivative cash settlement (gain) loss
(1)
|
(22,062
|
)
|
|
(44,264
|
)
|
|
25,671
|
|
|||
|
|
|
|
|
|
||||||
Derivative (gain) loss:
|
|
|
|
|
|
||||||
Oil contracts
|
(496
|
)
|
|
(31,981
|
)
|
|
(3,391
|
)
|
|||
Gas contracts
|
16,285
|
|
|
31,777
|
|
|
(64,310
|
)
|
|||
NGL contracts
|
3,193
|
|
|
(11,162
|
)
|
|
4,944
|
|
|||
Total derivative gain
(2)
|
$
|
(3,080
|
)
|
|
$
|
(55,630
|
)
|
|
$
|
(37,086
|
)
|
(1)
|
Total derivative cash settlement gain (loss) is reported in the derivative cash settlement gain (loss) line item on the consolidated statements of cash flows within net cash provided by operating activities.
|
(2)
|
Total derivative gain is reported in the derivative gain line item on the consolidated statements of cash flows within net cash provided by operating activities.
|
|
|
|
Location on
Accompanying
Statements of
Operations
|
|
For the Years Ended December 31,
|
||||||||||
|
Derivatives
|
|
|
2013
|
|
2012
|
|
2011
|
|||||||
|
|
|
|
|
(in thousands)
|
||||||||||
Amount reclassified from
AOCIL
|
Commodity Contracts
|
|
Realized hedge gain (loss)
|
|
$
|
1,115
|
|
|
$
|
(2,264
|
)
|
|
$
|
12,997
|
|
•
|
Level 1 – quoted prices in active markets for identical assets or liabilities
|
•
|
Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
|
•
|
Level 3 – significant inputs to the valuation model are unobservable
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
52,510
|
|
|
$
|
—
|
|
Proved oil and gas properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
62,178
|
|
Unproved oil and gas properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,280
|
|
Oil and gas properties held for sale
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
650
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
31,020
|
|
|
$
|
—
|
|
Net Profits Plan
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
56,985
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
54,339
|
|
|
$
|
—
|
|
Proved oil and gas properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
209,959
|
|
Unproved oil and gas properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
42,765
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
15,644
|
|
|
$
|
—
|
|
Net Profits Plan
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
78,827
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
78,827
|
|
|
$
|
107,731
|
|
|
$
|
135,850
|
|
Net increase (decrease) in liability
(1)
|
3,527
|
|
|
(9,251
|
)
|
|
2,269
|
|
|||
Net settlements
(1) (2) (3)
|
(25,369
|
)
|
|
(19,653
|
)
|
|
(30,388
|
)
|
|||
Transfers in (out) of Level 3
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance
|
$
|
56,985
|
|
|
$
|
78,827
|
|
|
$
|
107,731
|
|
(1)
|
Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations.
|
(2)
|
Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued under the Net Profits Plan of
$10.3 million
,
$2.3 million
, and
$6.3 million
relating to divestiture proceeds for the years ended
December 31, 2013
,
2012
, and
2011
, respectively.
|
(3)
|
During 2011, the Company elected to cash out several Net Profits Plan pools with a
$2.6 million
direct payment. As a result, the Company reduced its Net Profits Plan liability by that amount. There was no impact on the accompanying statements of operations for the period ended December 31, 2011, related to these settlements.
|
|
As of December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in thousands)
|
||||||
2019 Notes
|
$
|
374,290
|
|
|
$
|
371,875
|
|
2021 Notes
|
$
|
373,625
|
|
|
$
|
371,070
|
|
2023 Notes
|
$
|
422,000
|
|
|
$
|
424,200
|
|
2024 Notes
(1)
|
$
|
475,315
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance on January 1,
|
$
|
9,100
|
|
|
$
|
18,600
|
|
|
$
|
35,862
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
34,527
|
|
|
9,100
|
|
|
15,618
|
|
|||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
|
(9,100
|
)
|
|
(5,865
|
)
|
|
(32,880
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
—
|
|
|
(12,735
|
)
|
|
—
|
|
|||
Ending balance at December 31,
|
$
|
34,527
|
|
|
$
|
9,100
|
|
|
$
|
18,600
|
|
|
As of December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Exploratory well costs capitalized for one year or less
|
$
|
34,527
|
|
|
$
|
9,100
|
|
|
$
|
15,618
|
|
Exploratory well costs capitalized for more than one year
|
—
|
|
|
—
|
|
|
2,982
|
|
|||
Ending balance at December 31,
|
$
|
34,527
|
|
|
$
|
9,100
|
|
|
$
|
18,600
|
|
Number of projects with exploratory well costs that have been capitalized more than a year
|
—
|
|
|
—
|
|
|
2
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Development costs
(1)
|
$
|
1,350,116
|
|
|
$
|
1,346,216
|
|
|
$
|
1,320,627
|
|
Exploration costs
|
168,612
|
|
|
220,921
|
|
|
177,465
|
|
|||
Acquisitions
|
|
|
|
|
|
||||||
Proved properties
|
29,859
|
|
|
5,773
|
|
|
—
|
|
|||
Unproved properties
(2)
|
172,546
|
|
|
114,971
|
|
|
55,237
|
|
|||
Total, including asset retirement obligation
(3)(4)
|
$
|
1,721,133
|
|
|
$
|
1,687,881
|
|
|
$
|
1,553,329
|
|
(1)
|
Includes facility costs of
$49.5 million
,
$62.2 million
, and
$112.4 million
for the years ended
December 31, 2013
,
2012
, and
2011
, respectively.
|
(2)
|
Includes
$58.5 million
and
$3.4 million
of unproved properties acquired as part of a proved property acquisition for the years ended
December 31, 2013
and
2012
, respectively. The remaining balance relates to leasing activity.
|
(3)
|
Includes capitalized interest of
$11.0 million
,
$12.1 million
, and
$10.8 million
for the years ended
December 31, 2013
,
2012
, and
2011
, respectively.
|
(4)
|
Includes amounts relating to estimated asset retirement obligations of
$26.8 million
,
$30.6 million
, and
$19.3 million
for the years ended
December 31, 2013
,
2012
, and
2011
, respectively.
|
|
||||||||||||||||||||||||||
|
For the Years Ended December 31,
|
|||||||||||||||||||||||||
|
2013
(1)
|
|
2012
(2)
|
|
2011
(3)
|
|||||||||||||||||||||
|
Oil
|
|
Gas
|
|
NGLs
|
|
Oil
|
|
Gas
|
|
NGLs
|
|
Oil
|
|
Gas
|
|
NGLs
|
|||||||||
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|||||||||
Total proved reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of year
|
92.2
|
|
|
833.4
|
|
|
62.3
|
|
|
71.7
|
|
|
664.0
|
|
|
27.5
|
|
|
57.4
|
|
|
640.0
|
|
|
—
|
|
Revisions of previous estimate
|
(5.2
|
)
|
|
68.8
|
|
|
(1.3
|
)
|
|
(4.5
|
)
|
|
(123.3
|
)
|
|
(2.4
|
)
|
|
(0.9
|
)
|
|
(76.7
|
)
|
|
15.6
|
|
Discoveries and extensions
|
34.6
|
|
|
399.2
|
|
|
39.8
|
|
|
17.1
|
|
|
297.4
|
|
|
30.6
|
|
|
26.9
|
|
|
223.5
|
|
|
17.8
|
|
Infill reserves in an existing proved field
|
21.6
|
|
|
118.7
|
|
|
13.2
|
|
|
19.2
|
|
|
125.1
|
|
|
12.7
|
|
|
2.8
|
|
|
14.8
|
|
|
0.5
|
|
Sales of
reserves
(4)
|
(3.4
|
)
|
|
(85.1
|
)
|
|
(0.6
|
)
|
|
(1.0
|
)
|
|
(11.0
|
)
|
|
—
|
|
|
(6.4
|
)
|
|
(37.3
|
)
|
|
(2.9
|
)
|
Purchases of minerals in place
|
0.7
|
|
|
3.6
|
|
|
—
|
|
|
0.1
|
|
|
1.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(13.9
|
)
|
|
(149.3
|
)
|
|
(9.5
|
)
|
|
(10.4
|
)
|
|
(120.0
|
)
|
|
(6.1
|
)
|
|
(8.1
|
)
|
|
(100.3
|
)
|
|
(3.5
|
)
|
End of year
(5)
|
126.6
|
|
|
1,189.3
|
|
|
103.9
|
|
|
92.2
|
|
|
833.4
|
|
|
62.3
|
|
|
71.7
|
|
|
664.0
|
|
|
27.5
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of year
|
58.8
|
|
|
483.2
|
|
|
27.2
|
|
|
50.3
|
|
|
451.2
|
|
|
15.2
|
|
|
46.0
|
|
|
411.0
|
|
|
—
|
|
End of year
|
70.2
|
|
|
569.2
|
|
|
43.8
|
|
|
58.8
|
|
|
483.2
|
|
|
27.2
|
|
|
50.3
|
|
|
451.2
|
|
|
15.2
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of year
|
33.5
|
|
|
350.2
|
|
|
35.1
|
|
|
21.4
|
|
|
212.8
|
|
|
12.3
|
|
|
11.4
|
|
|
229.0
|
|
|
—
|
|
End of year
|
56.3
|
|
|
620.1
|
|
|
60.2
|
|
|
33.5
|
|
|
350.2
|
|
|
35.1
|
|
|
21.4
|
|
|
212.8
|
|
|
12.3
|
|
(1)
|
For the year ended December 31, 2013, of the
5.0
MMBOE upward revision of a previous estimate,
0.6
MMBOE and
4.4
MMBOE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2013, were
$96.94
per Bbl,
$3.67
per MMBtu, and
$40.29
per Bbl for oil, natural gas, and NGLs respectively. These prices were
two percent
higher,
33 percent
higher, and
12 percent
lower, respectively, than the prices used in 2012. The Company added
195.5
MMBOE from its drilling program, the majority of which related to activity in the Eagle Ford shale in South Texas and Bakken/Three Forks plays in North Dakota. These additions are included in discoveries and extensions and infill reserves.
|
(2)
|
For the year ended December 31, 2012, of the
27.4
MMBOE downward revision of a previous estimate,
12.1
MMBOE and
15.3
MMBOE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2012, were
$94.71
per Bbl,
$2.76
per MMBtu, and
$45.65
per Bbl for oil, natural gas, and NGLs respectively. These prices were
two percent
lower,
33 percent
lower, and
23 percent
lower, respectively, than the prices used in 2011. The Company added
150.0
MMBOE from its drilling program, the majority of which related to activity in the Eagle Ford shale in South Texas. These additions are included in discoveries and extensions and infill reserves.
|
(3)
|
For the year ended December 31, 2011, of the
1.9
MMBOE upward revision of a previous estimate,
(4.2)
MMBOE and
6.1
MMBOE relate to price and performance revisions, respectively. The prices used in the calculation of proved
|
(4)
|
The Company divested of certain non-core assets during
2013
,
2012
, and
2011
. Please refer to
Note 3 - Divestitures and Assets Held for Sale
for additional information.
|
(5)
|
For the years ended
December 31, 2013
,
2012
, and
2011
, amounts included approximately
12
,
50
, and
29
MBOE respectively, representing the Company’s net underproduced gas balancing position.
|
|
As of December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Future cash inflows
|
$
|
19,895,360
|
|
|
$
|
13,129,243
|
|
|
$
|
10,871,281
|
|
Future production costs
|
(7,771,747
|
)
|
|
(5,013,720
|
)
|
|
(3,786,887
|
)
|
|||
Future development costs
|
(2,891,325
|
)
|
|
(1,742,978
|
)
|
|
(1,036,352
|
)
|
|||
Future income taxes
|
(2,722,230
|
)
|
|
(1,609,397
|
)
|
|
(1,740,394
|
)
|
|||
Future net cash flows
|
6,510,058
|
|
|
4,763,148
|
|
|
4,307,648
|
|
|||
10 percent annual discount
|
(2,500,619
|
)
|
|
(1,742,134
|
)
|
|
(1,727,608
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
4,009,439
|
|
|
$
|
3,021,014
|
|
|
$
|
2,580,040
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in thousands)
|
||||||||||
Standardized measure, beginning of year
|
$
|
3,021,014
|
|
|
$
|
2,580,040
|
|
|
$
|
1,666,367
|
|
Sales of oil, gas, and NGLs produced, net of production costs
|
(1,602,505
|
)
|
|
(1,081,997
|
)
|
|
(1,042,281
|
)
|
|||
Net changes in prices and production costs
|
142,199
|
|
|
(550,293
|
)
|
|
454,646
|
|
|||
Extensions, discoveries and other including infill reserves in an existing proved field, net of related costs
|
2,309,075
|
|
|
1,872,810
|
|
|
1,816,640
|
|
|||
Sales of reserves in place
|
(259,031
|
)
|
|
(41,020
|
)
|
|
(369,820
|
)
|
|||
Purchase of reserves in place
|
30,771
|
|
|
3,785
|
|
|
—
|
|
|||
Development costs incurred during the year
|
581,107
|
|
|
163,937
|
|
|
49,246
|
|
|||
Changes in estimated future development costs
|
68,613
|
|
|
47,980
|
|
|
(31,410
|
)
|
|||
Revisions of previous quantity estimates
|
82,226
|
|
|
(452,454
|
)
|
|
32,992
|
|
|||
Accretion of discount
|
384,914
|
|
|
346,118
|
|
|
234,433
|
|
|||
Net change in income taxes
|
(690,953
|
)
|
|
53,005
|
|
|
(203,169
|
)
|
|||
Changes in timing and other
|
(57,991
|
)
|
|
79,103
|
|
|
(27,604
|
)
|
|||
Standardized measure, end of year
|
$
|
4,009,439
|
|
|
$
|
3,021,014
|
|
|
$
|
2,580,040
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
(2)
|
||||||||
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
||||||||
Year Ended December 31, 2013
|
|
|
|
|
|
|
|
||||||||
Total operating revenues
|
$
|
484,180
|
|
|
$
|
559,360
|
|
|
$
|
613,107
|
|
|
$
|
636,727
|
|
Total operating expenses
|
437,982
|
|
|
415,076
|
|
|
475,623
|
|
|
596,438
|
|
||||
Income from operations
|
$
|
46,198
|
|
|
$
|
144,284
|
|
|
$
|
137,484
|
|
|
$
|
40,289
|
|
Income before income taxes
|
$
|
27,109
|
|
|
$
|
122,727
|
|
|
$
|
113,024
|
|
|
$
|
15,751
|
|
Net income
|
$
|
16,727
|
|
|
$
|
76,522
|
|
|
$
|
70,690
|
|
|
$
|
6,996
|
|
Basic net income per common share
(1)
|
$
|
0.25
|
|
|
$
|
1.15
|
|
|
$
|
1.06
|
|
|
$
|
0.10
|
|
Diluted net income per common share
(1)
|
$
|
0.25
|
|
|
$
|
1.13
|
|
|
$
|
1.04
|
|
|
$
|
0.10
|
|
Dividends declared per common share
|
$
|
0.05
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2012
|
|
|
|
|
|
|
|
||||||||
Total operating revenues
|
$
|
377,423
|
|
|
$
|
304,420
|
|
|
$
|
378,951
|
|
|
$
|
444,308
|
|
Total operating expenses
|
321,198
|
|
|
252,029
|
|
|
421,787
|
|
|
530,105
|
|
||||
Income (loss) from operations
|
$
|
56,225
|
|
|
$
|
52,391
|
|
|
$
|
(42,836
|
)
|
|
$
|
(85,797
|
)
|
Income (loss) before income taxes
|
$
|
42,017
|
|
|
$
|
39,684
|
|
|
$
|
(61,072
|
)
|
|
$
|
(104,146
|
)
|
Net income (loss)
|
$
|
26,336
|
|
|
$
|
24,889
|
|
|
$
|
(38,336
|
)
|
|
$
|
(67,138
|
)
|
Basic net income (loss) per common share
(1)
|
$
|
0.41
|
|
|
$
|
0.39
|
|
|
$
|
(0.58
|
)
|
|
$
|
(1.02
|
)
|
Diluted net income (loss) per common share
(1)
|
$
|
0.39
|
|
|
$
|
0.37
|
|
|
$
|
(0.58
|
)
|
|
$
|
(1.02
|
)
|
Dividends declared per common share
|
$
|
0.05
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
(i)
|
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
|
(ii)
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
|
(iii)
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements.
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
(1)
|
In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energy or any affiliate of SM Energy. The Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the SM Energy Company Restricted Stock Plan, and the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All grants of equity are now made under the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan in 2009, 2010, and 2013 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The awards granted in
2013
,
2012
, and
2011
under the Equity Plan were
632,939
,
724,671
, and
386,802
, respectively.
|
(2)
|
Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled
77,427
,
66,485
, and
41,358
in
2013
,
2012
, and
2011
, respectively.
|
(3)
|
RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per share fair value for the outstanding RSUs and PSUs was
$57.05
and $67.74, respectively. Please refer to
Note 7 - Compensation Plans
for additional discussion.
|
(4)
|
The number of awards vested assumes a
one
multiplier. The final number of shares issued upon settlement may vary depending on the
three
-year multiplier determined at the end of the performance period under the Equity Plan, which ranges from
zero
to
two
.
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
Exhibit
Number
|
Description
|
|
|
2.1
|
Purchase and Sale Agreement dated June 9, 2011, among SM Energy Company, Statoil Texas Onshore Properties LLC, and Talisman Energy USA Inc. (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by reference)
|
2.2
|
Acquisition and Development Agreement dated June 29, 2011 between SM Energy Company and Mitsui E&P Texas LP (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by reference)
|
2.3
|
First Amendment to Acquisition and Development Agreement dated October 13, 2011 between SM Energy Company and Mitsui E&P Texas (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 and incorporated herein by reference)
|
2.4*††
|
Purchase and Sale Agreement dated November 4, 2013, among SM Energy Company, EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., and EnerVest Energy Institutional Fund XIII-WIC, L.P.
|
3.1
|
Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)
|
3.2
|
Amended and Restated By-Laws of SM Energy Company amended effective as of January 1, 2013 (filed as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on January 7, 2013, and incorporated herein by reference)
|
4.1
|
Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007, between St. Mary Land & Exploration Company and Wells Fargo Bank, National Association, as trustee (including the form of 3.50% Senior Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on April 4, 2007 and incorporated herein by reference)
|
4.2
|
Indenture related to the 6.625% Senior Notes due 2019, dated as of February 7, 2011, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference)
|
4.3
|
Indenture related to the 6.50% Senior Notes due 2021, dated as of November 8, 2011, by and among SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on November 10, 2011, and incorporated herein by reference)
|
4.4
|
Indenture related to the 6.50% Senior Notes due 2023, dated June 29, 2012, between SM Energy Company, as Issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by reference)
|
4.5
|
Indenture related to the 5.0% Senior Notes due 2024, dated May 20, 2013, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant's Current Report on Form 8-K filed on May 20, 2013, and incorporated herein by reference)
|
4.6
|
Registration Rights Agreement, dated May 20, 2013, by and among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities, LLC, and J.P. Morgan Securities LLC, as representatives of several purchasers (filed as Exhibit 4.2 to the registrant's Current Report on Form 8-K filed on May 20, 2013, and incorporated herein by reference)
|
10.1†
|
Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference)
|
10.2†
|
Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference)
|
10.3†
|
Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference)
|
10.4†
|
Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.9 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference)
|
10.5†
|
Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 4, 2006 and incorporated herein by reference)
|
10.6
|
Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference)
|
10.7
|
Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference)
|
10.8†
|
Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2009, and incorporated herein by reference)
|
10.9†
|
Equity Incentive Compensation Plan As Amended and Restated as of April 1, 2010 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference)
|
10.10
s
|
SM Energy Company Equity Incentive Compensation Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)
|
10.11†
|
Third Amendment to Employee Stock Purchase Plan dated September 23, 2009 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, and incorporated herein by reference)
|
10.12†
|
Fourth Amendment to Employee Stock Purchase Plan dated December 29, 2009 (filed as Exhibit 10.46 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference)
|
10.13
s
|
Employee Stock Purchase Plan, As Amended and Restated as of July 30, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)
|
10.14†
|
Form of Performance Share and Restricted Stock Unit Award Agreement as of July 1, 2010 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)
|
10.15†
|
Form of Performance Share and Restricted Stock Unit Award Notice as of July 1, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)
|
10.16†
|
Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)
|
10.17***
|
Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)
|
10.18
s
|
Cash Bonus Plan, As Amended on July 30, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)
|
10.19
s
|
Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)
|
10.20
s
|
SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)
|
10.21†
|
Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on December 29, 2010, and incorporated herein by reference)
|
10.22†
|
Amendment to A.J. Best Employment Agreement dated December 31, 2010 (filed as Exhibit 10.28 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)
|
10.23
|
Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit 10.30 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)
|
10.24+
|
SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of November 9, 2010 (filed as Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)
|
10.25
|
Fourth Amended and Restated Credit Agreement dated May 27, 2011 among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.26
|
Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.27
|
Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company and ETC Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.28
|
Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM Energy Company (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.29†
|
Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.30†
|
Form of Performance Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.31†
|
Form of Restricted Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
|
10.32†
|
Form of Performance Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference)
|
10.33†
|
Form of Restricted Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference)
|
10.34
|
Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filed as Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference)
|
10.35
|
Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filed as Exhibit 10.42 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference)
|
10.36†
|
Equity Incentive Compensation Plan, As Amended as of May 22, 2013 (filed as Annex A to the registrant’s Schedule 14A filed on April 11, 2013, and incorporated herein by reference)
|
10.37
|
Fifth Amended and Restated Credit Agreement dated April 12, 2013, among SM Energy Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report of Form 8-K filed on April 15, 2013, and incorporated herein by reference)
|
10.38†
|
Form of Performance Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference)
|
10.39†
|
Form of Restricted Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference)
|
10.40†
|
SM Energy Company Non-Qualified Deferred Compensation Plan as of March 10, 2014 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on January 24, 2014, and incorporated herein by reference)
|
10.41*†
|
Cash Bonus Plan, As Amended and Restated as of February 1, 2014
|
10.42*†
|
Summary of Compensation Arrangements for Non-Employee Directors
|
12.1*
|
Computation of Ratio of Earnings to Fixed Charges
|
21.1*
|
Subsidiaries of Registrant
|
23.1*
|
Consent of Ernst & Young LLP
|
23.2*
|
Consent of Deloitte & Touche LLP
|
23.3*
|
Consent of Ryder Scott Company L.P.
|
24.1*
|
Power of Attorney
|
31.1*
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
|
31.2*
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
|
32.1**
|
Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002
|
99.1*
|
Ryder Scott Audit Letter
|
101.INS*
|
XBRL Instance Document
|
101.SCH*
|
XBRL Schema Document
|
101.CAL*
|
XBRL Calculation Linkbase Document
|
101.LAB*
|
XBRL Label Linkbase Document
|
101.PRE*
|
XBRL Presentation Linkbase Document
|
101.DEF*
|
XBRL Taxonomy Extension Definition Linkbase Document
|
***
|
Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934.
|
††
|
Confidential Treatment has been requested with respect to portions of the exhibit. Such portions have been redacted and filed separately with the SEC.
|
†
|
Exhibit constitutes a management contract or compensatory plan or agreement.
|
s
|
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the recent change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document.
|
+
|
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document.
|
|
|
SM ENERGY COMPANY
|
|
|
|
(Registrant)
|
|
|
|
|
|
Date:
|
February 19, 2014
|
By:
|
/s/ ANTHONY J. BEST
|
|
|
|
Anthony J. Best
|
|
|
|
Chief Executive Officer
|
|
|
|
(Principal Executive Officer)
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ ANTHONY J. BEST
|
|
Chief Executive Officer and Director
|
|
February 19, 2014
|
Anthony J. Best
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ A. WADE PURSELL
|
|
Executive Vice President and Chief Financial Officer
|
|
February 19, 2014
|
A. Wade Pursell
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ MARK T. SOLOMON
|
|
Vice President - Controller and Assistant Secretary
|
|
February 19, 2014
|
Mark T. Solomon
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ WILLIAM D. SULLIVAN
|
|
Chairman of the Board of Directors
|
|
February 19, 2014
|
William D. Sullivan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ BARBARA M. BAUMANN
|
|
Director
|
|
February 19, 2014
|
Barbara M. Baumann
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ LARRY W. BICKLE
|
|
Director
|
|
February 19, 2014
|
Larry W. Bickle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ STEPHEN R. BRAND
|
|
Director
|
|
February 19, 2014
|
Stephen R. Brand
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ WILLIAM J. GARDINER
|
|
Director
|
|
February 19, 2014
|
William J. Gardiner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ LOREN M. LEIKER
|
|
Director
|
|
February 19, 2014
|
Loren
M. Leiker
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ JULIO M. QUINTANA
|
|
Director
|
|
February 19, 2014
|
Julio M. Quintana
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ JOHN M. SEIDL
|
|
Director
|
|
February 19, 2014
|
John M. Seidl
|
|
|
|
|
|
|
|
|
|
Article I DEFINITIONS; INTERPRETATION
|
1
|
|
|
1.1
|
Definitions
|
1
|
|
1.2
|
Interpretation
|
1
|
|
Article II Purchase and Sale
|
2
|
|
|
2.1
|
Purchase and Sale
|
2
|
|
2.2
|
Purchase Price
|
2
|
|
2.3
|
Deposit
|
2
|
|
2.4
|
Adjustments to Purchase Price
|
3
|
|
2.5
|
Allocated Value
|
5
|
|
2.6
|
Settlement; Disputes
|
5
|
|
2.7
|
Section 1031 Like-Kind Exchange
|
6
|
|
Article III REPRESENTATIONS AND WARRANTIES OF SM ENERGY
|
7
|
|
|
3.1
|
Organization, Existence
|
7
|
|
3.2
|
Authorization
|
7
|
|
3.3
|
No Conflicts
|
7
|
|
3.4
|
Bankruptcy
|
7
|
|
3.5
|
Foreign Person
|
7
|
|
3.6
|
Litigation
|
8
|
|
3.7
|
Material Contracts
|
8
|
|
3.8
|
No Violation of Laws
|
9
|
|
3.9
|
Royalties, Etc.
|
9
|
|
3.10
|
Imbalances
|
9
|
|
3.11
|
Current Commitments
|
9
|
|
3.12
|
Environmental
|
9
|
|
3.13
|
Asset Taxes
|
9
|
|
3.14
|
Brokers’ Fees
|
9
|
|
3.15
|
Advance Payments
|
9
|
|
3.16
|
Partnerships
|
10
|
|
3.17
|
Payout Balances
|
10
|
|
3.18
|
Preferential Rights to Purchase and Consents
|
10
|
|
3.19
|
No Other Representations or Warranties; Disclosed Materials
|
10
|
|
Article IV REPRESENTATIONS AND WARRANTIES OF BUYER
|
10
|
|
|
4.1
|
Organization; Existence
|
10
|
|
4.2
|
Authorization
|
11
|
|
4.3
|
No Conflicts
|
11
|
|
4.4
|
Consents
|
11
|
|
4.5
|
Bankruptcy
|
11
|
|
4.6
|
Litigation
|
11
|
|
4.7
|
Financing
|
11
|
|
4.8
|
Independent Evaluation
|
12
|
|
4.9
|
Brokers’ Fees
|
12
|
|
4.1
|
Accredited Investor
|
12
|
|
Article V ACCESS / DISCLAIMERS
|
12
|
|
|
5.1
|
Access
|
12
|
|
5.2
|
Confidentiality
|
14
|
|
5.3
|
Disclaimers.
|
14
|
|
Article VI TITLE MATTERS; CASUALTIES
|
16
|
|
|
6.1
|
SM Energy’s Title
|
16
|
|
6.2
|
Notice of Title Defects; Defect Adjustments
|
16
|
|
6.3
|
Casualty or Condemnation Loss
|
20
|
|
6.4
|
Preferential Rights and Consents to Assign
|
21
|
|
Article VII ENVIRONMENTAL MATTERS
|
22
|
|
|
7.1
|
Environmental Defects
|
22
|
|
7.2
|
NORM, Wastes and Other Substances
|
25
|
|
Article VIII CERTAIN AGREEMENTS
|
25
|
|
|
8.1
|
Conduct of Business
|
25
|
|
8.2
|
Governmental Bonds
|
27
|
|
8.3
|
Notifications
|
27
|
|
8.4
|
Suspense Accounts
|
27
|
|
8.5
|
Digital Records
|
27
|
|
8.6
|
[***]
|
27
|
|
Article IX CONDITIONS TO CLOSING
|
28
|
|
|
9.1
|
Buyer’s Conditions to Closing
|
28
|
|
9.2
|
SM Energy’s Conditions to Closing
|
29
|
|
Article X Tax Matters
|
29
|
|
|
10.1
|
Asset Tax Liability
|
29
|
|
10.2
|
Transfer Taxes
|
30
|
|
10.3
|
Asset Tax Reports and Returns
|
30
|
|
10.4
|
Tax Cooperation
|
30
|
|
Article XI CLOSING
|
31
|
|
|
11.1
|
Date of Closing
|
31
|
|
11.2
|
Place of Closing
|
31
|
|
11.3
|
Closing Obligations
|
31
|
|
11.4
|
Records
|
32
|
|
Article XII ACQUISITION TERMINATION AND REMEDIES
|
32
|
|
|
12.1
|
Right of Termination
|
32
|
|
12.2
|
Effect of Termination
|
32
|
|
12.3
|
Specific Performance
|
33
|
|
12.4
|
Return of Documentation and Confidentiality
|
33
|
|
Article XIII ASSUMPTION; SURVIVAL; INDEMNIFICATION
|
33
|
|
|
13.1
|
Assumption by Buyer
|
33
|
|
13.2
|
Indemnities of SM Energy
|
34
|
|
13.3
|
Indemnities of Buyer
|
34
|
|
13.4
|
Limitation on Liability
|
35
|
|
13.5
|
Express Negligence
|
35
|
|
13.6
|
Exclusive Remedy for Agreement
|
35
|
|
13.7
|
Indemnification Procedures
|
36
|
|
13.8
|
Survival
|
38
|
|
13.9
|
Non-Compensatory Damages
|
38
|
|
Article XIV MISCELLANEOUS
|
39
|
|
|
14.1
|
Counterparts
|
39
|
|
14.2
|
Notices
|
39
|
|
14.3
|
Expenses
|
40
|
|
14.4
|
Waivers; Rights Cumulative
|
40
|
|
14.5
|
Relationship of the Parties
|
41
|
|
14.6
|
Entire Agreement; Conflicts
|
41
|
|
14.7
|
Governing Law
|
41
|
|
14.8
|
Filings, Notices and Certain Governmental Approvals
|
42
|
|
14.9
|
Amendment
|
42
|
|
14.1
|
Parties in Interest
|
42
|
|
14.11
|
Successors and Permitted Assigns
|
42
|
|
14.12
|
Publicity
|
42
|
|
14.13
|
Preparation of Agreement
|
42
|
|
14.14
|
Severability
|
42
|
|
Attention:
|
Herbert S. Vogel – Senior Vice President – Portfolio Development and Technical Services
|
Fax:
|
303.864.2598
|
Email:
|
hvogel@sm-energy.com
|
Attention:
|
David W. Copeland – Executive Vice President, General Counsel and Corporate Secretary
|
Title:
|
President and Chief Executive Officer
|
Title:
|
President and Chief Executive Officer
|
•
|
Audit Committee - $20,000
|
•
|
Compensation Committee - $15,000
|
•
|
Nominating and Corporate Governance Committee - $10,000
|
1)
|
Annual compensation payable upon election to the Board by the stockholders, valued at $160,000. This resulted in a grant of restricted stock to each non-employee director of 2,539 shares of SM Energy common stock issued on May 23, 2013, under SM Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year board service period and carry a subsequent one-year transfer restriction imposed by SM Energy.
|
2)
|
A retainer for the Non-Executive Chairman of the Board valued at $75,000. This resulted in a grant of 1,191 shares of SM Energy common stock issued on May 23, 2013, under SM Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year board service period and carry a subsequent one-year transfer restriction imposed by SM Energy.
|
3)
|
Barbara M. Baumann, Larry W. Bickle, William J. Gardiner, Loren M. Leiker, Julio M. Quintana and William D. Sullivan each elected to receive SM Energy common stock for their retainer, which resulted in a grant of 1,111 shares of SM Energy common stock issued on May 23, 2013, under SM Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year Board service period and carry a subsequent one-year transfer restriction imposed by SM Energy. Stephen R. Brand and John M. Seidl each elected to receive a $70,000 cash payment for their retainer.
|
|
Year Ended December 31,
|
||||||||||||||
|
2013
|
2012
|
2011
|
2010
|
2009
|
||||||||||
|
(in thousands, except ratios)
|
||||||||||||||
|
|
|
|
|
|
||||||||||
Pretax income from continuing operations
|
$
|
278,611
|
|
$
|
(83,517
|
)
|
$
|
339,001
|
|
$
|
314,896
|
|
$
|
(159,464
|
)
|
|
|
|
|
|
|
||||||||||
Add: Fixed charges
|
102,758
|
|
77,841
|
|
58,030
|
|
29,558
|
|
31,702
|
|
|||||
Add: Amortization of capitalized interest
|
11,784
|
|
9,095
|
|
5,107
|
|
2,991
|
|
2,697
|
|
|||||
Less: Capitalized interest
|
(10,952
|
)
|
(12,135
|
)
|
(10,785
|
)
|
(4,337
|
)
|
(1,902
|
)
|
|||||
Earnings before fixed charges
|
$
|
382,201
|
|
$
|
(8,716
|
)
|
$
|
391,353
|
|
$
|
343,108
|
|
$
|
(126,967
|
)
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
||||||||||
Interest expense
(1)
|
89,711
|
|
63,720
|
|
45,849
|
|
24,196
|
|
28,856
|
|
|||||
Capitalized interest
|
10,952
|
|
12,135
|
|
10,785
|
|
4,337
|
|
1,902
|
|
|||||
Interest expense component of rent
(2)
|
2,095
|
|
1,986
|
|
1,396
|
|
1,025
|
|
944
|
|
|||||
Total fixed charges
|
$
|
102,758
|
|
$
|
77,841
|
|
$
|
58,030
|
|
$
|
29,558
|
|
$
|
31,702
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
3.7
|
|
—
|
|
6.7
|
|
11.6
|
|
—
|
|
|||||
Insufficient coverage
|
$
|
—
|
|
$
|
86,557
|
|
$
|
—
|
|
$
|
—
|
|
$
|
158,669
|
|
A.
|
Wholly-owned subsidiaries of SM Energy Company, a Delaware corporation:
|
1.
|
Box Church Gas Gathering, LLC, a Colorado limited liability company (59%)
|
C.
|
Partnership or limited liability company interests held by SM Energy Company:
|
1.
|
Potato Creek Midstream, LLC, a Pennsylvania limited liability company (70%)
|
2.
|
Trinity River Systems, LTD, a Texas limited partnership (21%)
|
3.
|
1977 H.B Joint Account, a Colorado general partnership (8%)
|
4.
|
1976 H.B Joint Account, a Colorado general partnership (9%)
|
5.
|
1974 H.B Joint Account, a Colorado general partnership (4%)
|
6.
|
Sycamore Gas Systems, an Oklahoma general partnership (3%)
|
1.
|
St. Mary Land East Texas LP, a Texas limited partnership (99%) (the remaining 1% interest is held by SM Energy Company)
|
1.
|
I have reviewed this annual report on Form 10-K of SM Energy Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
1.
|
I have reviewed this annual report on Form 10-K of SM Energy Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
/s/ Michael F. Stell
|
|
/s/ James L. Baird
|
Michael F. Stell, P.E.
|
|
James L. Baird
|
TBPE License No. 56416
|
|
Colorado License No. 41521
|
Advising Senior Vice President
|
|
Managing Senior Vice President
|
As of December 31, 2013
|
|
|
Proved
|
||||||
|
|
Developed
|
|
|
|
Total
|
||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
Net Reserves of Properties
Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBarrels
|
|
46,520
|
|
1,437
|
|
54,522
|
|
102,479
|
Plant Products - MBarrels
|
|
40,426
|
|
2,512
|
|
59,894
|
|
102,832
|
Gas – MMCF
|
|
456,768
|
|
20,397
|
|
593,805
|
|
1,070,970
|
|
|
|
|
|
|
|
|
|
Net Reserves of Properties
Not Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBarrels
|
|
21,115
|
|
1,155
|
|
1,820
|
|
24,090
|
Plant Products – MBarrels
|
|
576
|
|
252
|
|
275
|
|
1,103
|
Gas – MMCF
|
|
79,097
|
|
12,898
|
|
26,339
|
|
118,334
|
|
|
|
|
|
|
|
|
|
Total Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate - MBarrels
|
|
67,635
|
|
2,592
|
|
56,342
|
|
126,569
|
Plant Products – MBarrels
|
|
41,002
|
|
2,764
|
|
60,169
|
|
103,935
|
Gas – MMCF
|
|
535,865
|
|
33,295
|
|
620,144
|
|
1,189,304
|
(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.
|