Delaware
(State or other jurisdiction
of incorporation or organization)
|
41-0518430
(I.R.S. Employer Identification No.)
|
1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
|
80203
(Zip Code)
|
Title of each class
|
|
Name of each exchange on which registered
|
Common stock, $.01 par value
|
|
New York Stock Exchange
|
Large accelerated filer
þ
|
Accelerated filer
o
|
Non-accelerated filer
o
(Do not check if a smaller reporting company)
|
Smaller reporting company
o
|
TABLE OF CONTENTS
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ITEM
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TABLE OF CONTENTS
|
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(Continued)
|
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ITEM
|
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PAGE
|
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||
•
|
Resource Play Delineation and Development Results in Record Production and Increase in Year-End Proved Reserve Estimates.
Our estimated proved reserves increased 28 percent to 1,259.2 BCFE at December 31, 2011, from 984.5 BCFE at December 31, 2010. We added 526.1 BCFE through drilling activity during the year, which was primarily led by our efforts in the Eagle Ford shale in South Texas, the Bakken/Three Forks plays in North Dakota, and the Haynesville shale in East Texas. We achieved record levels of production in 2011. Our average daily production was composed of
274.8
MMcf of gas,
22.1
MBbl of oil, and
9.6
MBbl of NGLs for an average equivalent production rate of
465.0
MMCFE per day, which was an increase of 54 percent from
301.4
MMCFE per day in 2010. Costs incurred in 2011 for drilling and exploration activities and acquisitions increased
77 percent
, to
$1.6 billion
, compared with
$877.4
million in 2010. The increase in capital investment reflects increased confidence in our drilling inventory, particularly in plays with significant oil and NGL-rich gas components, such as our Eagle Ford shale and Bakken/Three Forks plays. Please refer to
Core Operational Areas
below for additional discussion concerning our 2011 estimated proved reserves, production, and capital investment.
|
•
|
Acquisition and Development Agreement.
In December 2011, we closed on our Acquisition and Development Agreement with Mitsui E&P Texas LP ("Mitsui"), an indirect subsidiary of Mitsui & Co. Ltd., which transferred 12.5 percent of our working interest in certain non-operated oil and gas assets in South Texas. Under the agreement, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs for wells targeting the Eagle Ford shale attributable to our remaining interests in these assets, until Mitsui has expended an aggregate of $680.0 million on our behalf. Please refer to
Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement
in Part II, Item 8 of this report for additional discussion concerning this transaction.
|
•
|
Financing Activities.
During 2011, our financing activities consisted of the following transactions:
|
•
|
issuance of $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 ("6.625% Senior Notes");
|
•
|
issuance of $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021 ("6.50% Senior Notes"); and
|
•
|
execution of a
$2.5 billion
Fourth Amended and Restated Credit Agreement with a borrowing base of
$1.3 billion
and lender commitments of
$1.0 billion
, as of December 31, 2011.
|
•
|
Impairments.
We recognized
$219.0 million
of proved property impairments for the year ended December 31, 2011. A significant decrease in natural gas prices during the second half of 2011 led to the impairment of certain dry gas assets in our ArkLaTex region.
|
•
|
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 development of assets with higher potential value and for other general corporate purposes. Often, but not always, we divest of properties with higher operating costs and/or limited future drilling or development potential. During 2011, we sold 93.1 BCFE of reserves, the majority of which related to assets located in our South Texas & Gulf Coast region. The following transactions represent our most significant divestitures during 2011:
|
•
|
Eagle Ford Shale Divestiture.
In
August 2011
, we completed the divestiture of certain operated Eagle Ford shale assets located in our South Texas & Gulf Coast region. This position comprised our entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of our operated acreage in Dimmit County, Texas. Total divestiture proceeds, before marketing costs, Net Profits Interest Bonus Plan ("Net Profits Plan") payments, and legal fees (referred to subsequently as "divestiture proceeds"), were
$230.8 million
. The estimated gain on this divestiture was
$194.6 million
and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012.
|
•
|
Mid-Continent Divestiture.
In
June 2011
, we completed the divestiture of certain non-strategic assets located in our Mid-Continent region. Total divestiture proceeds were
$35.8 million
. The estimated gain on this divestiture was
$28.5 million
and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012.
|
•
|
Rocky Mountain Divestiture.
In
January 2011
, we completed the divestiture of certain non-strategic assets located in our Rocky Mountain region. Total divestiture proceeds were
$45.5 million
. The final gain on this divestiture was
$27.2 million
.
|
|
ArkLaTex
|
|
Mid-
Continent
|
|
South Texas & Gulf Coast
|
|
Permian
|
|
Rocky
Mountain
|
|
Total
(1)
|
||||||||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Oil (MMBbl)
|
0.3
|
|
|
0.8
|
|
|
14.6
|
|
|
12.4
|
|
|
43.7
|
|
|
71.7
|
|
||||||
Gas (Bcf)
|
124.0
|
|
|
223.9
|
|
|
243.0
|
|
|
31.7
|
|
|
41.5
|
|
|
664.0
|
|
||||||
NGLs (MMBbl)
|
0.9
|
|
|
1.0
|
|
|
25.5
|
|
|
0.2
|
|
|
—
|
|
|
27.5
|
|
||||||
Equivalents (BCFE)
|
130.6
|
|
|
234.6
|
|
|
483.6
|
|
|
107.0
|
|
|
303.4
|
|
|
1,259.2
|
|
||||||
Relative percentage
|
10
|
%
|
|
19
|
%
|
|
38
|
%
|
|
9
|
%
|
|
24
|
%
|
|
100
|
%
|
||||||
Proved Developed %
|
76
|
%
|
|
75
|
%
|
|
54
|
%
|
|
86
|
%
|
|
71
|
%
|
|
67
|
%
|
||||||
PV-10 Values (in millions)
(2)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved Developed
|
$
|
173.7
|
|
|
$
|
353.9
|
|
|
$
|
857.7
|
|
|
$
|
459.8
|
|
|
$
|
991.2
|
|
|
$
|
2,836.3
|
|
Proved Undeveloped
(3)
|
16.9
|
|
|
42.3
|
|
|
294.5
|
|
|
51.4
|
|
|
219.8
|
|
|
624.9
|
|
||||||
Total Proved
|
$
|
190.6
|
|
|
$
|
396.2
|
|
|
$
|
1,152.2
|
|
|
$
|
511.2
|
|
|
$
|
1,211
|
|
|
$
|
3,461.2
|
|
Relative percentage
|
6
|
%
|
|
11
|
%
|
|
33
|
%
|
|
15
|
%
|
|
35
|
%
|
|
100
|
%
|
||||||
Production
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Oil (MMBbl)
|
0.1
|
|
|
0.4
|
|
|
2.6
|
|
|
1.3
|
|
|
3.7
|
|
|
8.1
|
|
||||||
Gas (Bcf)
|
29.3
|
|
|
28.6
|
|
|
34.7
|
|
|
3.5
|
|
|
4.2
|
|
|
100.3
|
|
||||||
NGLs (MMBbl)
|
0.1
|
|
|
0.1
|
|
|
3.2
|
|
|
—
|
|
|
—
|
|
|
3.5
|
|
||||||
Equivalent (BCFE)
|
30.1
|
|
|
31.6
|
|
|
69.7
|
|
|
11.5
|
|
|
26.7
|
|
|
169.7
|
|
||||||
Avg. Daily Equivalents
(MMCFE/d)
|
82.5
|
|
|
86.7
|
|
|
191.1
|
|
|
31.5
|
|
|
73.3
|
|
|
465.0
|
|
||||||
Relative percentage
|
18
|
%
|
|
19
|
%
|
|
41
|
%
|
|
6
|
%
|
|
16
|
%
|
|
100
|
%
|
(1)
|
Totals may not sum 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)
|
We record estimates of proved undeveloped reserves for locations with a positive PV-0 value when we have the intent to drill the location and it meets our economic criteria.
|
|
As of December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Reserve data:
|
|
|
|
|
|
||||||
Proved developed
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
50.3
|
|
|
46.0
|
|
|
48.1
|
|
|||
Gas (Bcf)
|
451.2
|
|
|
411.0
|
|
|
342.0
|
|
|||
NGLs (MMBbl)
|
15.2
|
|
|
-
|
|
|
-
|
|
|||
BCFE
|
844.0
|
|
|
687.3
|
|
|
630.3
|
|
|||
Proved undeveloped
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
21.4
|
|
|
11.4
|
|
|
5.7
|
|
|||
Gas (Bcf)
|
212.8
|
|
|
229.0
|
|
|
107.5
|
|
|||
NGLs (MMBbl)
|
12.3
|
|
|
-
|
|
|
-
|
|
|||
BCFE
|
415.2
|
|
|
297.2
|
|
|
141.9
|
|
|||
Total Proved
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
71.7
|
|
|
57.4
|
|
|
53.8
|
|
|||
Gas (Bcf)
|
664.0
|
|
|
640.0
|
|
|
449.5
|
|
|||
NGLs (MMBbl)
|
27.5
|
|
|
-
|
|
|
-
|
|
|||
BCFE
|
1,259.2
|
|
|
984.5
|
|
|
772.2
|
|
|||
Proved developed reserves %
|
67
|
%
|
|
70
|
%
|
|
82
|
%
|
|||
Proved undeveloped reserves %
|
33
|
%
|
|
30
|
%
|
|
18
|
%
|
|||
|
|
|
|
|
|
||||||
Reserve value data (in millions):
|
|
|
|
|
|
||||||
Proved developed PV-10
|
$
|
2,836.3
|
|
|
$
|
2,053.5
|
|
|
$
|
1,253.1
|
|
Proved undeveloped PV-10
|
624.9
|
|
|
290.8
|
|
|
31.0
|
|
|||
Total proved PV-10
|
$
|
3,461.2
|
|
|
$
|
2,344.3
|
|
|
$
|
1,284.1
|
|
Standardized measure of discounted future cash flows
|
$
|
2,580.0
|
|
|
$
|
1,666.4
|
|
|
$
|
1,016.0
|
|
|
|
|
|
|
|
||||||
Reserve replacement – drilling , excluding revisions
|
310
|
%
|
|
349
|
%
|
|
100
|
%
|
|||
All in – including sales of reserves
|
262
|
%
|
|
293
|
%
|
|
14
|
%
|
|||
All in – excluding sales of reserves
|
317
|
%
|
|
372
|
%
|
|
55
|
%
|
|||
Reserve life (years)
(1)
|
7.4
|
|
|
8.9
|
|
|
7.1
|
|
|
As of December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in millions)
|
||||||||||
Standardized measure of discounted future net cash flows
|
$
|
2,580.0
|
|
|
$
|
1,666.4
|
|
|
$
|
1,016.0
|
|
Add: 10 percent annual discount, net of income taxes
|
1,727.6
|
|
|
1,294.6
|
|
|
733.0
|
|
|||
Add: future undiscounted income taxes
|
1,740.4
|
|
|
1,335.5
|
|
|
515.9
|
|
|||
Undiscounted future net cash flows
|
$
|
6,048.0
|
|
|
$
|
4,296.5
|
|
|
$
|
2,264.9
|
|
Less: 10 percent annual discount without tax effect
|
(2,586.8
|
)
|
|
(1,952.2
|
)
|
|
(980.8
|
)
|
|||
PV-10 value
|
$
|
3,461.2
|
|
|
$
|
2,344.3
|
|
|
$
|
1,284.1
|
|
|
Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Net production
(1)
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
8.1
|
|
|
6.4
|
|
|
6.3
|
|
|||
Gas (Bcf)
|
100.3
|
|
|
71.9
|
|
|
71.1
|
|
|||
NGLs (MMBbl)
|
3.5
|
|
|
—
|
|
|
—
|
|
|||
BCFE
|
169.7
|
|
|
110.0
|
|
|
109.1
|
|
|||
Average net daily production
(1)
|
|
|
|
|
|
||||||
Oil (MBbl per day)
|
22.1
|
|
|
17.4
|
|
|
17.3
|
|
|||
Gas (MMcf per day)
|
274.8
|
|
|
196.9
|
|
|
194.8
|
|
|||
NGLs (MBbl per day)
|
9.6
|
|
|
—
|
|
|
—
|
|
|||
MMCFE per day
|
465.0
|
|
|
301.4
|
|
|
298.8
|
|
|||
Realized price
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
88.23
|
|
|
$
|
72.65
|
|
|
$
|
54.40
|
|
Gas (per Mcf)
|
$
|
4.32
|
|
|
$
|
5.21
|
|
|
$
|
3.82
|
|
NGLs (per Bbl)
|
$
|
53.32
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Per MCFE
|
$
|
7.85
|
|
|
$
|
7.60
|
|
|
$
|
5.65
|
|
Production costs per MCFE
|
|
|
|
|
|
||||||
Lease operating expense
|
$
|
0.88
|
|
|
$
|
1.10
|
|
|
$
|
1.33
|
|
Transportation costs
|
$
|
0.51
|
|
|
$
|
0.19
|
|
|
$
|
0.19
|
|
Production taxes
|
$
|
0.32
|
|
|
$
|
0.48
|
|
|
$
|
0.37
|
|
(1)
|
In 2011 and 2010, total estimated proved reserves for our Eagle Ford shale properties equated to greater than 15 percent of our total proved reserves expressed on an equivalent basis. During 2011, our net production from the Eagle Ford shale was 32.9 Bcf of gas, 2.5 MMBbl of oil, and 3.1 MMBbl of NGLs or 66.6 BCFE. Our average daily production from the Eagle Ford shale was 90.1 MMcf of gas, 6.8 MBbl of oil, and 8.6 MBbl of NGLs, for an average production rate of 182.5 MMCFE per day. During 2010, our net production from the Eagle Ford shale was 13.0 Bcf of gas and 0.8 MMBbl of oil, or 17.6 BCFE. Our average daily production from the Eagle Ford shale was 35.6 MMcf of gas and 2.1 MBbl of oil, for an average production rate of 48.3 MMCFE per day. No fields contained 15 percent or greater of our total proved reserves expressed on an equivalent basis in 2009.
|
|
Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
125
|
|
32.1
|
|
191
|
|
36.5
|
|
103
|
|
29.6
|
Gas
|
273
|
|
81.0
|
|
72
|
|
17.0
|
|
74
|
|
18.2
|
Non-productive
|
11
|
|
4.0
|
|
4
|
|
1.1
|
|
3
|
|
1.3
|
|
409
|
|
117.1
|
|
267
|
|
54.6
|
|
180
|
|
49.1
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
16
|
|
6.3
|
|
36
|
|
11.5
|
|
2
|
|
0.4
|
Gas
|
48
|
|
8.6
|
|
83
|
|
37.9
|
|
18
|
|
9.1
|
Non-productive
|
3
|
|
1.0
|
|
1
|
|
0.8
|
|
5
|
|
2.9
|
|
67
|
|
15.9
|
|
120
|
|
50.2
|
|
25
|
|
12.4
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
476
|
|
133.0
|
|
387
|
|
104.8
|
|
205
|
|
61.5
|
|
Developed Acres
(1)
|
|
Undeveloped Acres
(2)
|
|
Total
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Louisiana
|
70,632
|
|
|
26,049
|
|
|
16,367
|
|
|
4,716
|
|
|
86,999
|
|
|
30,765
|
|
Montana
|
59,071
|
|
|
40,655
|
|
|
315,582
|
|
|
212,371
|
|
|
374,653
|
|
|
253,026
|
|
Nevada
|
-
|
|
|
-
|
|
|
197,634
|
|
|
197,634
|
|
|
197,634
|
|
|
197,634
|
|
North Dakota
|
134,647
|
|
|
88,865
|
|
|
158,543
|
|
|
87,186
|
|
|
293,190
|
|
|
176,051
|
|
Oklahoma
|
257,348
|
|
|
82,962
|
|
|
39,280
|
|
|
14,334
|
|
|
296,628
|
|
|
97,296
|
|
Pennsylvania
|
346
|
|
|
346
|
|
|
49,676
|
|
|
39,749
|
|
|
50,022
|
|
|
40,095
|
|
Texas
|
211,525
|
|
|
135,211
|
|
|
489,922
|
|
|
226,543
|
|
|
701,447
|
|
|
361,754
|
|
Wyoming
|
62,936
|
|
|
28,305
|
|
|
304,603
|
|
|
166,371
|
|
|
367,539
|
|
|
194,676
|
|
Other
(3)
|
4,430
|
|
|
2,011
|
|
|
53,418
|
|
|
34,351
|
|
|
57,848
|
|
|
36,362
|
|
|
800,935
|
|
|
404,404
|
|
|
1,625,025
|
|
|
983,255
|
|
|
2,425,960
|
|
|
1,387,659
|
|
Louisiana Fee Properties
|
10,499
|
|
|
10,499
|
|
|
14,415
|
|
|
14,415
|
|
|
24,914
|
|
|
24,914
|
|
Louisiana Mineral Servitudes
|
7,426
|
|
|
4,217
|
|
|
4,769
|
|
|
4,407
|
|
|
12,195
|
|
|
8,624
|
|
|
17,925
|
|
|
14,716
|
|
|
19,184
|
|
|
18,822
|
|
|
37,109
|
|
|
33,538
|
|
Total
(4)
|
818,860
|
|
|
419,120
|
|
|
1,644,209
|
|
|
1,002,077
|
|
|
2,463,069
|
|
|
1,421,197
|
|
(1)
|
Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included 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 interest in Arkansas, Colorado, Illinois, Kansas, Mississippi, New Mexico, and Utah.
|
(4)
|
As of the filing date, we had approximately 50,000, 73,000, and 65,000 net acres scheduled to expire by December 31, 2012, 2013, and 2014, respectively, if production is not established or we take no other action to extend the terms.
|
•
|
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;
|
•
|
the continued 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 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 non-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 vendors, customers, or contractual counterparties to meet their obligations;
|
•
|
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 our ability 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;
|
•
|
operating and environmental risks and hazards that could result in substantial losses;
|
•
|
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 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;
|
•
|
the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas;
|
•
|
the price and availability of alternative fuels;
|
•
|
technological advances affecting energy consumption;
|
•
|
the ability of the members of the Organization of Petroleum 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.
|
•
|
the demand for crude oil, natural gas, and NGLs in the United States has declined and may remain at low levels or further decline if economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows, liquidity, and financial condition;
|
•
|
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, reduced demand in connection with the recent recession, and an unusually warm winter, which sustained low prices 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 exploration and/or development of our 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 drilling 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 or other adverse weather conditions;
|
•
|
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 repeal of the percentage depletion allowance for oil and natural gas properties;
|
•
|
the elimination of current deductions for intangible drilling and development costs;
|
•
|
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, 2011
|
|
$
|
88.50
|
|
$
|
53.45
|
September 30, 2011
|
|
|
85.55
|
|
|
60.52
|
June 30, 2011
|
|
|
78.55
|
|
|
61.37
|
March 31, 2011
|
|
|
75.00
|
|
|
54.59
|
|
|
|
|
|
|
|
December 31, 2010
|
|
$
|
59.82
|
|
$
|
37.30
|
September 30, 2010
|
|
|
44.93
|
|
|
33.80
|
June 30, 2010
|
|
|
49.13
|
|
|
35.29
|
March 31, 2010
|
|
|
38.18
|
|
|
30.70
|
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, 2011 –
March 31, 2011
|
8,878
|
|
|
$
|
72.47
|
|
|
—
|
|
|
3,072,184
|
|
April 1, 2011 -
June 30, 2011
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
July 1, 2011 -
September 30, 2011
|
123,504
|
|
|
$
|
75.49
|
|
|
—
|
|
|
3,072,184
|
|
October 1, 2011 -
October 31, 2011
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
November 1, 2011 -
November 30, 2011
|
88
|
|
|
$
|
78.92
|
|
|
—
|
|
|
3,072,184
|
|
December 1, 2011 -
December 31, 2011
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
3,072,184
|
|
Total October 1, 2011 -
December 31, 2011
|
88
|
|
|
$
|
78.92
|
|
|
—
|
|
|
3,072,184
|
|
Total
|
132,470
|
|
|
$
|
75.29
|
|
|
—
|
|
|
3,072,184
|
|
(1)
|
All shares purchased in 2011 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, 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 6.625% Senior Notes and 6.50% 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,
|
||||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
||||||||||
|
(in millions, except per share data)
|
||||||||||||||||||
Total operating revenues
|
$
|
1,603.3
|
|
|
$
|
1,092.8
|
|
|
$
|
832.2
|
|
|
$
|
1,301.3
|
|
|
$
|
990.1
|
|
Net income (loss)
|
$
|
215.4
|
|
|
$
|
196.8
|
|
|
$
|
(99.4
|
)
|
|
$
|
87.3
|
|
|
$
|
187.1
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
3.38
|
|
|
$
|
3.13
|
|
|
$
|
(1.59
|
)
|
|
$
|
1.40
|
|
|
$
|
3.02
|
|
Diluted
|
$
|
3.19
|
|
|
$
|
3.04
|
|
|
$
|
(1.59
|
)
|
|
$
|
1.38
|
|
|
$
|
2.90
|
|
Total assets at year-end
|
$
|
3,799.0
|
|
|
$
|
2,744.3
|
|
|
$
|
2,360.9
|
|
|
$
|
2,697.2
|
|
|
$
|
2,572.9
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
||||||||||
Line of credit
|
$
|
—
|
|
|
$
|
48.0
|
|
|
$
|
188.0
|
|
|
$
|
300.0
|
|
|
$
|
285.0
|
|
3.50% Senior Convertible Notes, net of debt discount
|
$
|
285.1
|
|
|
$
|
275.7
|
|
|
$
|
266.9
|
|
|
$
|
258.7
|
|
|
$
|
251.1
|
|
6.625% Senior Notes
|
$
|
350.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
6.50% Senior Notes
|
$
|
350.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Cash dividends declared and paid per common share
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
|
$
|
0.10
|
|
Supplemental Selected Financial and Operations Data
|
|||||||||||||||||||
|
|
||||||||||||||||||
|
Years Ended December 31,
|
||||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
||||||||||
|
|
||||||||||||||||||
Balance Sheet Data (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Total working capital (deficit)
|
$
|
(42.6
|
)
|
|
$
|
(227.4
|
)
|
|
$
|
(87.6
|
)
|
|
$
|
15.2
|
|
|
$
|
(92.6
|
)
|
Total stockholders’ equity
|
$
|
1,462.9
|
|
|
$
|
1,218.5
|
|
|
$
|
973.6
|
|
|
$
|
1,162.5
|
|
|
$
|
902.6
|
|
Weighted-average common shares outstanding (in thousands)
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
63,755
|
|
|
62,969
|
|
|
62,457
|
|
|
62,243
|
|
|
61,852
|
|
|||||
Diluted
|
67,564
|
|
|
64,689
|
|
|
62,457
|
|
|
63,133
|
|
|
64,850
|
|
|||||
Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
71.7
|
|
|
57.4
|
|
|
53.8
|
|
|
51.4
|
|
|
78.8
|
|
|||||
Gas (Bcf)
|
664.0
|
|
|
640.0
|
|
|
449.5
|
|
|
557.4
|
|
|
613.5
|
|
|||||
NGLs (MMBbl)
|
27.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
BCFE
|
1,259.2
|
|
|
984.5
|
|
|
772.2
|
|
|
865.5
|
|
|
1,086.5
|
|
|||||
Production and Operational (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil, gas, and NGL production revenues
|
$
|
1,332.4
|
|
|
$
|
836.3
|
|
|
$
|
616.0
|
|
|
$
|
1,259.4
|
|
|
$
|
912.1
|
|
Oil, gas, and NGL production expenses
|
$
|
290.1
|
|
|
$
|
195.1
|
|
|
$
|
206.8
|
|
|
$
|
271.4
|
|
|
$
|
218.2
|
|
DD&A
|
$
|
511.1
|
|
|
$
|
336.1
|
|
|
$
|
304.2
|
|
|
$
|
314.3
|
|
|
$
|
227.6
|
|
General and administrative
|
$
|
118.5
|
|
|
$
|
106.7
|
|
|
$
|
76.0
|
|
|
$
|
79.5
|
|
|
$
|
60.1
|
|
Production Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbl)
|
8.1
|
|
|
6.4
|
|
|
6.3
|
|
|
6.6
|
|
|
6.9
|
|
|||||
Gas (Bcf)
|
100.3
|
|
|
71.9
|
|
|
71.1
|
|
|
74.9
|
|
|
66.1
|
|
|||||
NGLs (MMBbl)
|
3.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
BCFE
|
169.7
|
|
|
110.0
|
|
|
109.1
|
|
|
114.6
|
|
|
107.5
|
|
|||||
Realized price
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
$
|
88.23
|
|
|
$
|
72.65
|
|
|
$
|
54.40
|
|
|
$
|
92.99
|
|
|
$
|
67.56
|
|
Gas (per Mcf)
|
$
|
4.32
|
|
|
$
|
5.21
|
|
|
$
|
3.82
|
|
|
$
|
8.60
|
|
|
$
|
6.74
|
|
NGL (per Bbl)
|
$
|
53.32
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Adjusted price (net of derivative cash settlements)
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
$
|
78.89
|
|
|
$
|
66.85
|
|
|
$
|
56.74
|
|
|
$
|
75.59
|
|
|
$
|
62.60
|
|
Gas (per Mcf)
|
$
|
4.80
|
|
|
$
|
6.05
|
|
|
$
|
5.59
|
|
|
$
|
8.79
|
|
|
$
|
7.63
|
|
NGL (per Bbl)
|
$
|
47.90
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Expense per MCFE
|
|
|
|
|
|
|
|
|
|
||||||||||
LOE
|
$
|
0.88
|
|
|
$
|
1.10
|
|
|
$
|
1.33
|
|
|
$
|
1.46
|
|
|
$
|
1.31
|
|
Transportation
|
$
|
0.51
|
|
|
$
|
0.19
|
|
|
$
|
0.19
|
|
|
$
|
0.19
|
|
|
$
|
0.14
|
|
Production taxes
|
$
|
0.32
|
|
|
$
|
0.48
|
|
|
$
|
0.37
|
|
|
$
|
0.71
|
|
|
$
|
0.58
|
|
DD&A
|
$
|
3.01
|
|
|
$
|
3.06
|
|
|
$
|
2.79
|
|
|
$
|
2.74
|
|
|
$
|
2.12
|
|
General and administrative
|
$
|
0.70
|
|
|
$
|
0.97
|
|
|
$
|
0.70
|
|
|
$
|
0.69
|
|
|
$
|
0.56
|
|
Statement of Cash Flow Data (in millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Provided by operations
|
$
|
760.5
|
|
|
$
|
497.1
|
|
|
$
|
436.1
|
|
|
$
|
679.2
|
|
|
$
|
632.1
|
|
(Used in) investing
|
$
|
(1,264.9
|
)
|
|
$
|
(361.6
|
)
|
|
$
|
(304.1
|
)
|
|
$
|
(673.8
|
)
|
|
$
|
(805.1
|
)
|
Provided by (used in) financing
|
$
|
618.5
|
|
|
$
|
(141.1
|
)
|
|
$
|
(127.5
|
)
|
|
$
|
(42.8
|
)
|
|
$
|
215.1
|
|
•
|
At year-end 2011, we had estimated proved reserves of 1,259.2 BCFE, of which 53 percent was natural gas and 67 percent was characterized as proved developed. We added 526.1 BCFE from our drilling program, the majority of which related to our activity in the Eagle Ford shale in South Texas, the Bakken/Three Forks plays in North Dakota, and the Haynesville Shale in East Texas. We sold 93.1 BCFE of proved reserves during the year related to assets located primarily in our South Texas & Gulf Coast region. We had negative price revisions that decreased our estimated proved reserves by 25.3 BCFE due to lower commodity prices in our gas-weighted regions. The prices used in the calculation of proved reserve estimates as of December 31, 2011, were
$96.19
per Bbl,
$4.12
per MMBtu, and
$59.37
per Bbl, for oil, natural gas, and NGLs, respectively. These prices were 21 percent higher for oil and six percent lower for natural gas than the prices used at year-end 2010. Performance revisions in 2011 resulted in a net 36.8 BCFE increase in our estimate of proved reserves. This increase includes the impact of our conversion to three stream production, which is partially offset by negative engineering revisions due primarily to the failure of Woodford shale wells in our Mid-Continent region to satisfy our internal economic hurdles due to current commodity prices and well costs.
|
•
|
The PV-10 value of our estimated proved reserves was
$3.5 billion
as of December 31, 2011, compared with $2.3 billion as of December 31, 2010. The after tax value, represented by the standardized measure calculation, was
$2.6 billion
as of December 31, 2011, compared with $1.7 billion as of
|
•
|
We had record production in 2011. Our average daily production in 2011 was
274.8
MMcf of gas,
22.1
MBbl of oil, and
9.6
MBbl of NGLs, for an average equivalent production rate of
465.0
MMCFE, compared with 301.4 MMCFE in 2010, an increase of 54 percent year over year.
|
•
|
We had record net income of
$215.4 million
and diluted earnings per share of
$3.19
for the year ended December 31, 2011. This compares with net income of
$196.8 million
, or
$3.04
per diluted share, for the year ended December 31, 2010.
|
•
|
We had record cash flow from operating activities of
$760.5 million
for the year ended December 31, 2011, compared with
$497.1 million
as of December 31, 2010, which was an increase of
53 percent
year over year.
|
•
|
Costs incurred for oil and gas producing activities for the year ended December 31, 2011, were
$1.6 billion
, compared with
$877.4 million
for the same period in 2010.
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Crude Oil (per Bbl):
|
|
|
|
|
|
||||||
Average NYMEX price
|
$
|
95.05
|
|
|
$
|
79.51
|
|
|
$
|
61.99
|
|
Realized price
|
$
|
88.23
|
|
|
$
|
72.65
|
|
|
$
|
54.40
|
|
|
|
|
|
|
|
||||||
Natural Gas (per Mcf):
|
|
|
|
|
|
||||||
Average NYMEX price
|
$
|
4.00
|
|
|
$
|
4.37
|
|
|
$
|
3.94
|
|
Realized price
|
$
|
4.32
|
|
|
$
|
5.21
|
|
|
$
|
3.82
|
|
|
|
|
|
|
|
||||||
NGLs (per Bbl):
|
|
|
|
|
|
||||||
Average OPIS price
|
$
|
59.47
|
|
|
$
|
34.61
|
|
|
$
|
46.92
|
|
Realized price
|
$
|
53.32
|
|
|
N/A
|
|
|
N/A
|
|
|
For the Year Ended
December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Crude Oil (per Bbl):
|
|
|
|
|
|
||||||
Realized price
|
$
|
88.23
|
|
|
$
|
72.65
|
|
|
$
|
54.40
|
|
Plus (less) the effects of derivative cash settlements
|
(9.34
|
)
|
|
(5.80
|
)
|
|
2.34
|
|
|||
Adjusted price, including the effects of derivative cash settlements
|
$
|
78.89
|
|
|
$
|
66.85
|
|
|
$
|
56.74
|
|
|
|
|
|
|
|
||||||
Natural Gas (per Mcf):
|
|
|
|
|
|
||||||
Realized price
|
$
|
4.32
|
|
|
$
|
5.21
|
|
|
$
|
3.82
|
|
Plus the effects of derivative cash settlements
|
0.48
|
|
|
0.84
|
|
|
1.77
|
|
|||
Adjusted price, including the effects of derivative cash settlements
|
$
|
4.80
|
|
|
$
|
6.05
|
|
|
$
|
5.59
|
|
|
|
|
|
|
|
||||||
Natural Gas Liquids (per Bbl):
|
|
|
|
|
|
||||||
Realized price
|
$
|
53.32
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(Less) the effects of derivative cash settlements
|
(5.42
|
)
|
|
—
|
|
|
—
|
|
|||
Adjusted price, including the effects of derivative cash settlements
|
$
|
47.90
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
ArkLaTex
|
|
Mid-Continent
|
|
South Texas & Gulf Coast
|
|
Permian
|
|
Rocky
Mountain
|
|
Total
(1)
|
||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MMBbl)
|
0.1
|
|
|
0.4
|
|
|
2.6
|
|
|
1.3
|
|
|
3.7
|
|
|
8.1
|
|
Gas (Bcf)
|
29.3
|
|
|
28.6
|
|
|
34.7
|
|
|
3.5
|
|
|
4.2
|
|
|
100.3
|
|
NGLs (MMBbl)
|
0.1
|
|
|
0.1
|
|
|
3.2
|
|
|
—
|
|
|
—
|
|
|
3.5
|
|
Equivalent (BCFE)
|
30.1
|
|
|
31.6
|
|
|
69.7
|
|
|
11.5
|
|
|
26.7
|
|
|
169.7
|
|
Avg. Daily Equivalents
(MMCFE/d)
|
82.5
|
|
|
86.7
|
|
|
191.1
|
|
|
31.5
|
|
|
73.3
|
|
|
465.0
|
|
Relative percentage
|
18
|
%
|
|
19
|
%
|
|
41
|
%
|
|
6
|
%
|
|
16
|
%
|
|
100
|
%
|
|
For the Year Ended
|
||
|
December 31, 2011
|
||
|
(in millions)
|
||
Development costs
|
$
|
1,208.3
|
|
Facility costs
|
112.4
|
|
|
Exploration costs
|
177.4
|
|
|
Acquisitions
|
|
||
Leasing activity
|
55.2
|
|
|
Total, including asset retirement obligation
|
$
|
1,553.3
|
|
•
|
Eagle Ford Shale Divestiture.
In
August 2011
, we completed the divestiture of certain operated Eagle Ford shale assets located in our South Texas & Gulf Coast region, comprised of our entire operated acreage position in LaSalle County, Texas, as well as an immaterial adjacent block of our operated acreage in Dimmit County, Texas. Total divestiture proceeds were
$230.8 million
. The estimated gain on this divestiture was
$194.6 million
and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012.
|
•
|
Mid-Continent Divestiture.
In
June 2011
, we completed the divestiture of certain non-strategic assets located in our Mid-Continent region. Total divestiture proceeds were
$35.8 million
. The estimated gain on this divestiture was
$28.5 million
and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012.
|
•
|
Rocky Mountain Divestiture.
In
January 2011
, we completed the divestiture of certain non-strategic assets located in our Rocky Mountain region. Total divestiture proceeds were
$45.5 million
. The final gain on this divestiture was
$27.2 million
.
|
•
|
Marcellus Divestiture Update
. In
July 2011
, we entered into agreements with Endeavour International Corporation ("Endeavour") to divest of our Marcellus shale assets and related pipeline
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2011
|
|
2011
|
|
2011
|
|
2011
|
||||||||
|
(in millions, except for production data)
|
||||||||||||||
Production (BCFE)
|
51.3
|
|
|
42.5
|
|
|
39.8
|
|
|
36.1
|
|
||||
Oil, gas, and NGL production revenue
|
$
|
397.0
|
|
|
$
|
325.2
|
|
|
$
|
333.9
|
|
|
$
|
276.3
|
|
Realized hedge loss
|
$
|
(6.2
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
(6.3
|
)
|
|
$
|
(1.4
|
)
|
Gain (loss) on divestiture activity
|
$
|
(25.0
|
)
|
|
$
|
190.7
|
|
|
$
|
30.0
|
|
|
$
|
24.9
|
|
Lease operating expense
|
$
|
43.5
|
|
|
$
|
40.0
|
|
|
$
|
33.2
|
|
|
$
|
33.1
|
|
Transportation costs
|
$
|
30.7
|
|
|
$
|
23.9
|
|
|
$
|
16.9
|
|
|
$
|
15.0
|
|
Production taxes
|
$
|
19.0
|
|
|
$
|
13.8
|
|
|
$
|
3.3
|
|
|
$
|
17.8
|
|
DD&A
|
$
|
167.3
|
|
|
$
|
123.1
|
|
|
$
|
115.4
|
|
|
$
|
105.4
|
|
Exploration
|
$
|
20.0
|
|
|
$
|
11.3
|
|
|
$
|
9.6
|
|
|
$
|
12.7
|
|
Impairment of proved properties
|
$
|
170.5
|
|
|
$
|
48.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
General and administrative
|
$
|
35.6
|
|
|
$
|
29.8
|
|
|
$
|
27.3
|
|
|
$
|
25.9
|
|
Change in Net Profits Plan liability
|
$
|
(0.8
|
)
|
|
$
|
(24.9
|
)
|
|
$
|
(14.0
|
)
|
|
$
|
14.2
|
|
Unrealized and realized derivative (gain) loss
|
$
|
46.8
|
|
|
$
|
(128.4
|
)
|
|
$
|
(43.9
|
)
|
|
$
|
88.4
|
|
Net income (loss)
|
$
|
(120.7
|
)
|
|
$
|
230.1
|
|
|
$
|
124.5
|
|
|
$
|
(18.5
|
)
|
|
For the Three Months Ended
|
||||||||||||||
|
December 31,
|
|
September 30,
|
|
June 30,
|
|
March 31,
|
||||||||
|
2011
|
|
2011
|
|
2011
|
|
2011
|
||||||||
Average net daily production equivalent (MMCFE per day)
|
557.9
|
|
|
462.1
|
|
|
436.9
|
|
|
401.4
|
|
||||
Lease operating expense (per MCFE)
|
$
|
(0.85
|
)
|
|
$
|
(0.94
|
)
|
|
$
|
(0.84
|
)
|
|
$
|
(0.92
|
)
|
Transportation costs (per MCFE)
|
$
|
(0.60
|
)
|
|
$
|
(0.56
|
)
|
|
$
|
(0.42
|
)
|
|
$
|
(0.41
|
)
|
Production taxes as a percent of oil, gas, and NGL production revenue
|
4.8
|
%
|
|
4.3
|
%
|
|
1.0
|
%
|
|
6.4
|
%
|
||||
Depletion, depreciation and amortization and asset retirement obligation liability accretion (per MCFE)
|
$
|
(3.26
|
)
|
|
$
|
(2.89
|
)
|
|
$
|
(2.90
|
)
|
|
$
|
(2.92
|
)
|
General and administrative (per MCFE)
|
$
|
(0.69
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.69
|
)
|
|
$
|
(0.72
|
)
|
|
As of and for the Years Ended December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
|
2011/2010
|
|
2010/2009
|
|
2011/2010
|
|
2010/2009
|
||||||||||||||
Net production volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MMBbl)
|
8.1
|
|
|
6.4
|
|
|
6.3
|
|
|
1.7
|
|
|
0.1
|
|
|
27
|
%
|
|
—
|
%
|
|||||||
Natural gas (Bcf)
|
100.3
|
|
|
71.9
|
|
|
71.1
|
|
|
28.5
|
|
|
0.8
|
|
|
40
|
%
|
|
1
|
%
|
|||||||
NGLs (MMBbl)
|
3.5
|
|
|
—
|
|
|
—
|
|
|
3.5
|
|
|
—
|
|
|
N/A
|
|
|
N/A
|
|
|||||||
BCFE
|
169.7
|
|
|
110.0
|
|
|
109.1
|
|
|
59.7
|
|
|
0.9
|
|
|
54
|
%
|
|
1
|
%
|
|||||||
Average net daily production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (MBbl per day)
|
22.1
|
|
|
17.4
|
|
|
17.3
|
|
|
4.7
|
|
|
0.1
|
|
|
27
|
%
|
|
—
|
%
|
|||||||
Natural gas (MMcf per day)
|
274.8
|
|
|
196.9
|
|
|
194.8
|
|
|
78.0
|
|
|
2.1
|
|
|
40
|
%
|
|
1
|
%
|
|||||||
NGLs (MBbl per day)
|
9.6
|
|
|
—
|
|
|
—
|
|
|
9.6
|
|
|
0.0
|
|
|
N/A
|
|
|
N/A
|
|
|||||||
Equivalent (MMCFE per day)
|
465.0
|
|
|
301.4
|
|
|
298.8
|
|
|
163.6
|
|
|
2.6
|
|
|
54
|
%
|
|
1
|
%
|
|||||||
Oil, gas, & NGL production revenues (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil production revenue
|
$
|
712.8
|
|
|
$
|
461.9
|
|
|
$
|
344.3
|
|
|
$
|
250.9
|
|
|
$
|
117.6
|
|
|
54
|
%
|
|
34
|
%
|
||
Gas production revenue
|
433.4
|
|
|
374.4
|
|
|
271.7
|
|
|
59.0
|
|
|
102.7
|
|
|
16
|
%
|
|
38
|
%
|
|||||||
NGL production revenue
|
186.2
|
|
|
—
|
|
|
—
|
|
|
186.2
|
|
|
—
|
|
|
N/A
|
|
|
N/A
|
|
|||||||
Total
|
$
|
1,332.4
|
|
|
$
|
836.3
|
|
|
$
|
616.0
|
|
|
$
|
496.1
|
|
|
$
|
220.3
|
|
|
59
|
%
|
|
36
|
%
|
||
Oil, gas, & NGL production expense (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expenses
|
$
|
149.8
|
|
|
$
|
121.5
|
|
|
$
|
145.5
|
|
|
$
|
28.3
|
|
|
$
|
(24.0
|
)
|
|
23
|
%
|
|
(16
|
)%
|
||
Transportation costs
|
86.4
|
|
|
21.2
|
|
|
20.6
|
|
|
65.2
|
|
|
0.6
|
|
|
308
|
%
|
|
3
|
%
|
|||||||
Production taxes
|
53.9
|
|
|
52.4
|
|
|
40.7
|
|
|
1.5
|
|
|
11.7
|
|
|
3
|
%
|
|
29
|
%
|
|||||||
Total
|
$
|
290.1
|
|
|
$
|
195.1
|
|
|
$
|
206.8
|
|
|
$
|
95.0
|
|
|
$
|
(11.7
|
)
|
|
49
|
%
|
|
(6
|
)%
|
||
Realized price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil (per Bbl)
|
$
|
88.23
|
|
|
$
|
72.65
|
|
|
$
|
54.40
|
|
|
$
|
15.58
|
|
|
$
|
18.25
|
|
|
21
|
%
|
|
34
|
%
|
||
Natural gas (per Mcf)
|
$
|
4.32
|
|
|
$
|
5.21
|
|
|
$
|
3.82
|
|
|
$
|
(0.89
|
)
|
|
$
|
1.39
|
|
|
(17
|
)%
|
|
36
|
%
|
||
NGLs (per Bbl)
|
$
|
53.32
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
53.32
|
|
|
$
|
—
|
|
|
N/A
|
|
|
N/A
|
|
||
Per MCFE data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Realized price
|
$
|
7.85
|
|
|
$
|
7.60
|
|
|
$
|
5.65
|
|
|
$
|
0.25
|
|
|
$
|
1.95
|
|
|
3
|
%
|
|
35
|
%
|
||
Lease operating expense
|
(0.88
|
)
|
|
(1.10
|
)
|
|
(1.33
|
)
|
|
0.22
|
|
|
0.23
|
|
|
(20
|
)%
|
|
(17
|
)%
|
|||||||
Transportation costs
|
(0.51
|
)
|
|
(0.19
|
)
|
|
(0.19
|
)
|
|
(0.32
|
)
|
|
—
|
|
|
168
|
%
|
|
—
|
%
|
|||||||
Production taxes
|
(0.32
|
)
|
|
(0.48
|
)
|
|
(0.37
|
)
|
|
0.16
|
|
|
(0.11
|
)
|
|
(33
|
)%
|
|
30
|
%
|
|||||||
General and administrative
|
(0.70
|
)
|
|
(0.97
|
)
|
|
(0.70
|
)
|
|
0.27
|
|
|
(0.27
|
)
|
|
(28
|
)%
|
|
39
|
%
|
|||||||
Operating profit, before the effects of derivative cash settlements
|
$
|
5.44
|
|
|
$
|
4.86
|
|
|
$
|
3.06
|
|
|
$
|
0.58
|
|
|
$
|
1.80
|
|
|
12
|
%
|
|
59
|
%
|
||
Derivative cash settlements
|
(0.27
|
)
|
|
0.22
|
|
|
1.29
|
|
|
(0.49
|
)
|
|
(1.07
|
)
|
|
(223
|
)%
|
|
(83
|
)%
|
|||||||
Operating profit, including the effects of derivative cash settlements
|
$
|
5.17
|
|
|
$
|
5.08
|
|
|
$
|
4.35
|
|
|
$
|
0.09
|
|
|
$
|
0.73
|
|
|
2
|
%
|
|
17
|
%
|
||
Depletion, depreciation and amortization and asset retirement obligation liability accretion
|
$
|
(3.01
|
)
|
|
$
|
(3.06
|
)
|
|
$
|
(2.79
|
)
|
|
$
|
0.05
|
|
|
$
|
(0.27
|
)
|
|
(2
|
)%
|
|
10
|
%
|
|
As of and for the Years Ended December 31,
|
|
Amount Change Between
|
|
Percent Change Between
|
||||||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
|
2011/ 2010
|
|
2010/ 2009
|
|
2011/ 2010
|
|
2010/ 2009
|
||||||||||||
Working deficit
|
$
|
(42.6
|
)
|
|
$
|
(227.4
|
)
|
|
$
|
(87.6
|
)
|
|
$
|
184.8
|
|
|
$
|
(139.8
|
)
|
|
(81
|
)%
|
|
160
|
%
|
Long-term debt
|
$
|
985.1
|
|
|
$
|
323.7
|
|
|
$
|
454.9
|
|
|
$
|
661.4
|
|
|
$
|
(131.2
|
)
|
|
204
|
%
|
|
(29
|
)%
|
Stockholders’ equity
|
$
|
1,462.9
|
|
|
$
|
1,218.5
|
|
|
$
|
973.6
|
|
|
$
|
244.4
|
|
|
$
|
244.9
|
|
|
20
|
%
|
|
25
|
%
|
Net income (loss)
|
$
|
215.4
|
|
|
$
|
196.8
|
|
|
$
|
(99.4
|
)
|
|
$
|
18.6
|
|
|
$
|
296.2
|
|
|
9
|
%
|
|
(298
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic net income (loss) per common share
|
$
|
3.38
|
|
|
$
|
3.13
|
|
|
$
|
(1.59
|
)
|
|
$
|
0.25
|
|
|
$
|
4.72
|
|
|
8
|
%
|
|
(297
|
)%
|
Diluted net income (loss) per common share
|
$
|
3.19
|
|
|
$
|
3.04
|
|
|
$
|
(1.59
|
)
|
|
$
|
0.15
|
|
|
$
|
4.63
|
|
|
5
|
%
|
|
(291
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic weighted-average common shares outstanding (in thousands)
|
63,755
|
|
|
62,969
|
|
|
62,457
|
|
|
786
|
|
|
512
|
|
|
1
|
%
|
|
1
|
%
|
|||||
Diluted weighted-average common shares outstanding (in thousands)
|
67,564
|
|
|
64,689
|
|
|
62,457
|
|
|
2,875
|
|
|
2,232
|
|
|
4
|
%
|
|
4
|
%
|
|
Average Net Daily Production Added (Lost)
|
|
Oil, Gas & NGL Revenue Added (Lost)
|
|
Production Costs Increase (Decrease)
|
|||||
|
(MMCFE/d)
|
|
(in millions)
|
|
(in millions)
|
|||||
ArkLaTex
|
43.2
|
|
|
$
|
57.6
|
|
|
$
|
5.2
|
|
Mid-Continent
|
(4.8
|
)
|
|
5.7
|
|
|
(1.1
|
)
|
||
South Texas & Gulf Coast
|
129.0
|
|
|
348.9
|
|
|
79.0
|
|
||
Permian
|
(8.7
|
)
|
|
(12.2
|
)
|
|
(0.3
|
)
|
||
Rocky Mountain
|
4.9
|
|
|
96.1
|
|
|
12.2
|
|
||
Total
|
163.6
|
|
|
$
|
496.1
|
|
|
$
|
95.0
|
|
|
For the Years Ended
December 31,
|
||||||
|
2011
|
|
2010
|
||||
Realized oil price ($/Bbl)
|
$
|
88.23
|
|
|
$
|
72.65
|
|
Realized gas price ($/Mcf)
|
$
|
4.32
|
|
|
$
|
5.21
|
|
Realized NGL price ($/Bbl)
|
$
|
53.32
|
|
|
$
|
—
|
|
Realized equivalent price ($/MCFE)
|
$
|
7.85
|
|
|
$
|
7.60
|
|
•
|
A $0.23 decrease in recurring LOE on a per MCFE basis reflects the sale of non-strategic properties in the Rocky Mountain and Mid-Continent regions in 2011 and the Permian region in late 2010 with higher per unit LOE costs that resulted in lower LOE on a per unit basis year over year. We expect that the various resources required to service our industry, particularly those located in basins with liquids-rich projects, will become more sought after and harder to secure as a result of an increase in activity targeting oil and NGL plays. Accordingly, we expect to see upward pressure on recurring LOE in 2012.
|
•
|
A $0.16 decrease in production taxes on a per MCFE basis is due to severance tax incentives in Texas that benefit our assets in the South Texas & Gulf Coast and Mid-Continent regions. Please refer to our production tax discussion under the caption
A year-to-year overview of selected production and financial information, including trends
for additional information.
|
•
|
A $0.01 increase in workover LOE on a per MCFE basis related primarily to increased workover activity in our South Texas & Gulf Coast region.
|
•
|
A $0.32 increase in transportation costs on a per MCFE basis is primarily the result of increased production in our Eagle Ford shale program, which has higher per unit transportation costs than our Company average. Please refer to our caption
A year-to-year overview of selected production and financial information, including trends
for additional information.
|
|
Years Ended December 31,
|
||||||
|
2011
|
|
2010
|
||||
Summary of Exploration Expense
|
(in millions)
|
||||||
Geological and geophysical expenses
|
$
|
7.3
|
|
|
$
|
21.5
|
|
Exploratory dry hole
|
0.3
|
|
|
0.3
|
|
||
Overhead and other expenses
|
45.9
|
|
|
42.1
|
|
||
Total
|
$
|
53.5
|
|
|
$
|
63.9
|
|
|
Average Net Daily Production Added (Lost)
|
|
Oil and Gas Revenue Added
|
|
Production Costs Increase (Decrease)
|
|||||
|
(MMCFE/d)
|
|
(in millions)
|
|
(in millions)
|
|||||
ArkLaTex
|
(1.5
|
)
|
|
$
|
7.4
|
|
|
$
|
(5.8
|
)
|
Mid-Continent
|
(7.2
|
)
|
|
23.9
|
|
|
4.0
|
|
||
South Texas & Gulf Coast
|
35.4
|
|
|
131.4
|
|
|
20.6
|
|
||
Permian
|
(1.3
|
)
|
|
37.8
|
|
|
2.2
|
|
||
Rocky Mountain
|
(22.8
|
)
|
|
19.8
|
|
|
(32.7
|
)
|
||
Total
|
2.6
|
|
|
$
|
220.3
|
|
|
$
|
(11.7
|
)
|
|
For the Years Ended
December 31,
|
||||||
|
2010
|
|
2009
|
||||
Realized oil price ($/Bbl)
|
$
|
72.65
|
|
|
$
|
54.40
|
|
Realized gas price ($/Mcf)
|
$
|
5.21
|
|
|
$
|
3.82
|
|
Realized equivalent price ($/MCFE)
|
$
|
7.60
|
|
|
$
|
5.65
|
|
•
|
A $0.23 decrease in recurring LOE on a per MCFE basis reflects the sale of non-strategic properties in late 2009 and early 2010 with higher per unit LOE costs, which resulted in lower LOE on a per unit basis year over year.
|
•
|
A $0.11 increase in production taxes on a per MCFE basis is due to the increase in realized prices between periods.
|
•
|
Workover LOE and transportation costs on a per MCFE basis remained flat year over year.
|
|
Years Ended December 31,
|
||||||
|
2010
|
|
2009
|
||||
Summary of Exploration Expense
|
(in millions)
|
||||||
Geological and geophysical expenses
|
$
|
21.5
|
|
|
$
|
20.2
|
|
Exploratory dry hole
|
0.3
|
|
|
7.8
|
|
||
Overhead and other expenses
|
42.1
|
|
|
34.2
|
|
||
Total
|
$
|
63.9
|
|
|
$
|
62.2
|
|
|
|
As of and for the Years Ended December 31,
|
Amount of Changes Between
|
|
Percent of Change Between
|
|||||||||||||||||
|
|
2011
|
2010
|
2009
|
|
2011/2010
|
2010/2009
|
|
2011/2010
|
2010/2009
|
||||||||||||
|
|
(in millions)
|
|
|
|
|||||||||||||||||
Net cash provided by operating activities
|
|
$
|
760.5
|
|
$
|
497.1
|
|
$
|
436.1
|
|
|
$
|
263.4
|
|
$
|
61.0
|
|
|
53
|
%
|
14
|
%
|
Net cash (used in) investing activities
|
|
$
|
(1,264.9
|
)
|
$
|
(361.6
|
)
|
$
|
(304.1
|
)
|
|
$
|
(903.3
|
)
|
$
|
(57.5
|
)
|
|
250
|
%
|
19
|
%
|
Net cash provided by (used in) financing activities
|
|
$
|
618.5
|
|
$
|
(141.1
|
)
|
$
|
(127.5
|
)
|
|
$
|
759.6
|
|
$
|
(13.6
|
)
|
|
(538
|
)%
|
11
|
%
|
Oil Swaps:
|
|
|
|
|
|
|
|||||
Contract Period
|
|
NYMEX WTI Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Fair Value at
December 31, 2011
(Liability)
|
|||||
|
|
(Bbls)
|
|
(per Bbl)
|
|
(in millions)
|
|||||
First quarter 2012
|
|
569,000
|
|
|
$
|
84.15
|
|
|
$
|
(8.5
|
)
|
Second quarter 2012
|
|
524,000
|
|
|
$
|
84.19
|
|
|
(7.9
|
)
|
|
Third quarter 2012
|
|
489,000
|
|
|
$
|
83.87
|
|
|
(7.2
|
)
|
|
Fourth quarter 2012
|
|
463,000
|
|
|
$
|
87.08
|
|
|
(5.0
|
)
|
|
2013
|
|
616,000
|
|
|
$
|
88.22
|
|
|
(4.8
|
)
|
|
2014
|
|
661,000
|
|
|
$
|
91.72
|
|
|
(0.9
|
)
|
|
All oil swaps
|
|
3,322,000
|
|
|
|
|
$
|
(34.3
|
)
|
Oil Collars:
|
|
|
|
|
|
|
|
|
|||||||
Contract Period
|
|
NYMEX WTI
Volumes
|
|
Weighted-
Average
Floor
Price
|
|
Weighted-
Average
Ceiling
Price
|
|
Fair Value at
December 31, 2011
Assets (Liability)
|
|||||||
|
|
(Bbls)
|
|
(per Bbl)
|
|
(per Bbl)
|
|
(in millions)
|
|||||||
First quarter 2012
|
|
391,000
|
|
|
$
|
76.58
|
|
|
$
|
109.96
|
|
|
$
|
(0.5
|
)
|
Second quarter 2012
|
|
372,000
|
|
|
$
|
76.55
|
|
|
$
|
109.88
|
|
|
(0.9
|
)
|
|
Third quarter 2012
|
|
347,000
|
|
|
$
|
76.45
|
|
|
$
|
109.70
|
|
|
(0.9
|
)
|
|
Fourth quarter 2012
|
|
325,000
|
|
|
$
|
76.34
|
|
|
$
|
109.60
|
|
|
(0.8
|
)
|
|
2013
|
|
2,147,000
|
|
|
$
|
75.84
|
|
|
$
|
109.81
|
|
|
(4.2
|
)
|
|
2014
|
|
560,000
|
|
|
$
|
80.00
|
|
|
$
|
116.05
|
|
|
1.2
|
|
|
All oil collars
|
|
4,142,000
|
|
|
|
|
|
|
$
|
(6.1
|
)
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|||||
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Fair Value at
December 31, 2011
Asset
|
|||||
|
|
(MMBtu)
|
|
(per MMBtu)
|
|
(in millions)
|
|||||
First quarter 2012
|
|
7,930,000
|
|
|
$
|
5.15
|
|
|
$
|
17.4
|
|
Second quarter 2012
|
|
7,140,000
|
|
|
$
|
4.77
|
|
|
12.6
|
|
|
Third quarter 2012
|
|
6,510,000
|
|
|
$
|
4.95
|
|
|
11.7
|
|
|
Fourth quarter 2012
|
|
6,020,000
|
|
|
$
|
5.20
|
|
|
10.7
|
|
|
2013
|
|
13,810,000
|
|
|
$
|
5.05
|
|
|
17.0
|
|
|
2014
|
|
2,910,000
|
|
|
$
|
5.42
|
|
|
3.3
|
|
|
All natural gas swaps*
|
|
44,320,000
|
|
|
|
|
$
|
72.7
|
|
Natural Gas Collars:
|
|
|
|
|
|
|
|
|
|||||
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Floor
Price
|
|
Weighted-
Average
Ceiling
Price
|
|
Fair Value at
December 31, 2011
Asset
|
|||||
|
|
(MMBtu)
|
|
(per MMBtu)
|
|
(per MMBtu)
|
|
(in millions)
|
|||||
2013
|
|
6,650,000
|
|
|
4.39
|
|
|
5.34
|
|
|
$
|
4.8
|
|
2014
|
|
5,734,000
|
|
|
4.38
|
|
|
5.36
|
|
|
2.7
|
|
|
All natural gas collars*
|
|
12,384,000
|
|
|
|
|
|
|
$
|
7.5
|
|
NGL Swaps:
|
|
|
|
|
|
|
|||||
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Fair Value at
December 31, 2011
(Liability)
|
|||||
|
|
(Bbls)
|
|
(per Bbl)
|
|
(in millions)
|
|||||
First quarter 2012
|
|
349,000
|
|
|
$
|
46.04
|
|
|
$
|
(3.4
|
)
|
Second quarter 2012
|
|
314,000
|
|
|
$
|
45.64
|
|
|
(2.2
|
)
|
|
Third quarter 2012
|
|
287,000
|
|
|
$
|
47.85
|
|
|
(1.1
|
)
|
|
Fourth quarter 2012
|
|
266,000
|
|
|
$
|
47.72
|
|
|
(1.0
|
)
|
|
2013
|
|
84,000
|
|
|
$
|
44.95
|
|
|
(0.9
|
)
|
|
All NGL swaps*
|
|
1,300,000
|
|
|
|
|
$
|
(8.6
|
)
|
Oil Collars:
|
|
|
|
|
|
|
|||||
Contract Period
|
|
NYMEX WTI
Volumes
|
|
Weighted-
Average
Floor
Price
|
|
Weighted-
Average
Ceiling
Price
|
|||||
|
|
(Bbls)
|
|
(per Bbl)
|
|
(per Bbl)
|
|||||
First quarter 2012
|
|
323,000
|
|
|
$
|
85.00
|
|
|
$
|
115.90
|
|
Second quarter 2012
|
|
371,000
|
|
|
$
|
85.00
|
|
|
$
|
115.90
|
|
Third quarter 2012
|
|
291,000
|
|
|
$
|
85.00
|
|
|
$
|
115.90
|
|
Fourth quarter 2012
|
|
241,000
|
|
|
$
|
85.00
|
|
|
$
|
115.90
|
|
2013
|
|
720,000
|
|
|
$
|
85.00
|
|
|
$
|
111.00
|
|
2014
|
|
1,614,000
|
|
|
$
|
85.00
|
|
|
$
|
105.12
|
|
All oil collars
|
|
3,560,000
|
|
|
|
|
|
Natural Gas Swaps:
|
|
|
|
|
|||
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(MMBtu)
|
|
(per MMBtu)
|
|||
Fourth quarter 2012
|
|
2,404,000
|
|
|
$
|
2.98
|
|
2013
|
|
6,699,000
|
|
|
$
|
3.43
|
|
2014
|
|
12,044,000
|
|
|
$
|
3.95
|
|
All natural gas swap contracts
|
|
21,147,000
|
|
|
|
NGL Swaps:
|
|
|
|
|
|||
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|||
|
|
(Bbls)
|
|
(per Bbl)
|
|||
First quarter 2012
|
|
61,000
|
|
|
$
|
83.11
|
|
Second quarter 2012
|
|
73,000
|
|
|
$
|
83.07
|
|
Third quarter 2012
|
|
59,000
|
|
|
$
|
83.09
|
|
Fourth quarter 2012
|
|
50,000
|
|
|
$
|
83.06
|
|
All NGL swap contracts
|
|
243,000
|
|
|
|
Contractual Obligations
|
|
Total
|
|
Less than 1 year
|
|
1-3 years
|
|
3-5 years
|
|
More than 5 years
|
||||||||||
Long-term debt
|
|
$
|
1,391.0
|
|
|
$
|
347.1
|
|
|
$
|
91.9
|
|
|
$
|
91.9
|
|
|
$
|
860.1
|
|
Derivative liability
|
|
55.9
|
|
|
42.9
|
|
|
13.0
|
|
|
—
|
|
|
—
|
|
|||||
Net Profits Plan
|
|
105.8
|
|
|
20.8
|
|
|
37.6
|
|
|
32.0
|
|
|
15.4
|
|
|||||
Delivery commitments
|
|
893.6
|
|
|
24.1
|
|
|
134.3
|
|
|
190.3
|
|
|
544.9
|
|
|||||
Operating leases and contracts
|
|
205.4
|
|
|
106.9
|
|
|
74.0
|
|
|
7.7
|
|
|
16.8
|
|
|||||
Other
|
|
18.6
|
|
|
6.5
|
|
|
11.4
|
|
|
0.3
|
|
|
0.4
|
|
|||||
Total
|
|
$
|
2,670.3
|
|
|
$
|
548.3
|
|
|
$
|
362.2
|
|
|
$
|
322.2
|
|
|
$
|
1,437.6
|
|
|
For the Years Ended December 31,
|
|||||||
|
2011
|
|
2010
|
|
2009
|
|||
|
BCFE
|
|
BCFE
|
|
BCFE
|
|||
|
Change
|
|
Change
|
|
Change
|
|||
Revisions resulting from price changes
|
(25.3
|
)
|
|
42.6
|
|
|
12.0
|
|
Revisions resulting from performance
|
36.8
|
|
|
(17.9
|
)
|
|
(61.6
|
)
|
Total
|
11.5
|
|
|
24.7
|
|
|
(49.6
|
)
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||||||||
|
BCFE
|
|
Percentage
|
|
BCFE
|
|
Percentage
|
|
BCFE
|
|
Percentage
|
||||||
|
Change
|
|
Change
|
|
Change
|
|
Change
|
|
Change
|
|
Change
|
||||||
A 10% decrease in SEC pricing
|
(22.2
|
)
|
|
(2
|
)%
|
|
(13.9
|
)
|
|
(1
|
)%
|
|
(25.1
|
)
|
|
(3
|
)%
|
A 10% decrease in proved undeveloped reserves
|
(41.5
|
)
|
|
(3
|
)%
|
|
(29.7
|
)
|
|
(3
|
)%
|
|
(14.2
|
)
|
|
(2
|
)%
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
December 31,
|
||||||
|
2011
|
|
2010
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
119,194
|
|
|
$
|
5,077
|
|
Accounts receivable (note 2)
|
210,368
|
|
|
163,190
|
|
||
Refundable income taxes
|
5,581
|
|
|
8,482
|
|
||
Prepaid expenses and other
|
68,026
|
|
|
45,522
|
|
||
Derivative asset
|
55,813
|
|
|
43,491
|
|
||
Deferred income taxes
|
4,222
|
|
|
8,883
|
|
||
Total current assets
|
463,204
|
|
|
274,645
|
|
||
|
|
|
|
||||
Property and equipment (successful efforts method), at cost:
|
|
|
|
||||
Land
|
1,548
|
|
|
1,491
|
|
||
Proved oil and gas properties
|
4,378,987
|
|
|
3,389,158
|
|
||
Less - accumulated depletion, depreciation, and amortization
|
(1,766,445
|
)
|
|
(1,326,932
|
)
|
||
Unproved oil and gas properties
|
120,966
|
|
|
94,290
|
|
||
Wells in progress
|
273,428
|
|
|
145,327
|
|
||
Materials inventory, at lower of cost or market
|
16,537
|
|
|
22,542
|
|
||
Oil and gas properties held for sale
|
246
|
|
|
86,811
|
|
||
Other property and equipment, net of accumulated depreciation of $23,985 in 2011 and $15,480 in 2010
|
71,369
|
|
|
21,365
|
|
||
Total property and equipment, net
|
3,096,636
|
|
|
2,434,052
|
|
||
|
|
|
|
||||
Other noncurrent assets:
|
|
|
|
||||
Derivative asset
|
31,062
|
|
|
18,841
|
|
||
Restricted cash (note 1)
|
124,703
|
|
|
—
|
|
||
Other noncurrent assets
|
83,375
|
|
|
16,783
|
|
||
Total other noncurrent assets
|
239,140
|
|
|
35,624
|
|
||
Total Assets
|
$
|
3,798,980
|
|
|
$
|
2,744,321
|
|
|
|
|
|
||||
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses (note 2)
|
$
|
456,999
|
|
|
$
|
417,654
|
|
Derivative liability
|
42,806
|
|
|
82,044
|
|
||
Other current liabilities
|
6,000
|
|
|
2,355
|
|
||
Total current liabilities
|
505,805
|
|
|
502,053
|
|
||
|
|
|
|
||||
Noncurrent liabilities:
|
|
|
|
||||
Long-term credit facility
|
—
|
|
|
48,000
|
|
||
3.50% Senior Convertible Notes, net of unamortized discount of $2,431 in 2011 and $11,827 in 2010
|
285,069
|
|
|
275,673
|
|
||
6.625% Senior Notes
|
350,000
|
|
|
—
|
|
||
6.50% Senior Notes
|
350,000
|
|
|
—
|
|
||
Asset retirement obligation
|
87,167
|
|
|
69,052
|
|
||
Asset retirement obligation associated with oil and gas properties held for sale
|
1,277
|
|
|
2,119
|
|
||
Net Profits Plan liability (note 11)
|
107,731
|
|
|
135,850
|
|
||
Deferred income taxes
|
568,263
|
|
|
443,135
|
|
||
Derivative liability
|
12,875
|
|
|
32,557
|
|
||
Other noncurrent liabilities
|
67,853
|
|
|
17,356
|
|
||
Total noncurrent liabilities
|
1,830,235
|
|
|
1,023,742
|
|
||
|
|
|
|
||||
Commitments and contingencies (note 6)
|
|
|
|
||||
|
|
|
|
||||
Stockholders' equity:
|
|
|
|
||||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 64,145,482 shares in 2011 and 63,412,800 shares in 2010; outstanding, net of treasury shares: 64,064,415 shares in 2011 and 63,310,165 shares in 2010
|
641
|
|
|
634
|
|
||
Additional paid-in capital
|
216,966
|
|
|
191,674
|
|
||
Treasury stock, at cost: 81,067 shares in 2011 and 102,635 shares in 2010
|
(1,544
|
)
|
|
(423
|
)
|
||
Retained earnings
|
1,251,157
|
|
|
1,042,123
|
|
||
Accumulated other comprehensive loss
|
(4,280
|
)
|
|
(15,482
|
)
|
||
Total stockholders' equity
|
1,462,940
|
|
|
1,218,526
|
|
||
Total Liabilities and Stockholders' Equity
|
$
|
3,798,980
|
|
|
$
|
2,744,321
|
|
|
For the Years
Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Operating revenues and other income:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production revenue
|
$
|
1,332,392
|
|
|
$
|
836,288
|
|
|
$
|
615,953
|
|
Realized hedge (loss) gain (note 10)
|
(20,707
|
)
|
|
23,465
|
|
|
140,648
|
|
|||
Gain on divestiture activity (note 3)
|
220,676
|
|
|
155,277
|
|
|
11,444
|
|
|||
Marketed gas system revenue
|
69,898
|
|
|
70,110
|
|
|
58,459
|
|
|||
Other operating revenue
|
1,059
|
|
|
7,694
|
|
|
5,697
|
|
|||
Total operating revenues and other income
|
1,603,318
|
|
|
1,092,834
|
|
|
832,201
|
|
|||
|
|
|
|
|
|
||||||
Operating expenses:
|
|
|
|
|
|
||||||
Oil, gas, and NGL production expense
|
290,111
|
|
|
195,075
|
|
|
206,800
|
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
511,103
|
|
|
336,141
|
|
|
304,201
|
|
|||
Exploration
|
53,537
|
|
|
63,860
|
|
|
62,235
|
|
|||
Impairment of proved properties
|
219,037
|
|
|
6,127
|
|
|
174,813
|
|
|||
Abandonment and impairment of unproved properties
|
7,367
|
|
|
1,986
|
|
|
45,447
|
|
|||
Impairment of materials inventory
|
—
|
|
|
—
|
|
|
14,223
|
|
|||
General and administrative
|
118,526
|
|
|
106,663
|
|
|
76,036
|
|
|||
Bad debt recovery
|
—
|
|
|
—
|
|
|
(5,189
|
)
|
|||
Change in Net Profits Plan liability
|
(25,477
|
)
|
|
(34,441
|
)
|
|
(7,075
|
)
|
|||
Unrealized and realized derivative (gain) loss (note 10)
|
(37,086
|
)
|
|
8,899
|
|
|
20,469
|
|
|||
Marketed gas system expense
|
64,249
|
|
|
66,726
|
|
|
57,587
|
|
|||
Other operating expense
|
17,567
|
|
|
3,027
|
|
|
13,489
|
|
|||
Total operating expenses
|
1,218,934
|
|
|
754,063
|
|
|
963,036
|
|
|||
|
|
|
|
|
|
||||||
Income (loss) from operations
|
384,384
|
|
|
338,771
|
|
|
(130,835
|
)
|
|||
|
|
|
|
|
|
||||||
Nonoperating income (expense):
|
|
|
|
|
|
||||||
Interest income
|
466
|
|
|
321
|
|
|
227
|
|
|||
Interest expense
|
(45,849
|
)
|
|
(24,196
|
)
|
|
(28,856
|
)
|
|||
|
|
|
|
|
|
||||||
Income (loss) before income taxes
|
339,001
|
|
|
314,896
|
|
|
(159,464
|
)
|
|||
Income tax (expense) benefit
|
(123,585
|
)
|
|
(118,059
|
)
|
|
60,094
|
|
|||
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
215,416
|
|
|
$
|
196,837
|
|
|
$
|
(99,370
|
)
|
|
|
|
|
|
|
||||||
Basic weighted-average common shares outstanding
|
63,755
|
|
|
62,969
|
|
|
62,457
|
|
|||
|
|
|
|
|
|
||||||
Diluted weighted-average common shares outstanding
|
67,564
|
|
|
64,689
|
|
|
62,457
|
|
|||
|
|
|
|
|
|
||||||
Basic net income (loss) per common share (note 1)
|
$
|
3.38
|
|
|
$
|
3.13
|
|
|
$
|
(1.59
|
)
|
|
|
|
|
|
|
||||||
Diluted net income (loss) per common share (note 1)
|
$
|
3.19
|
|
|
$
|
3.04
|
|
|
$
|
(1.59
|
)
|
|
|
|
Additional Paid-in Capital
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total Stockholders' Equity
|
||||||||||||||||
|
Common Stock
|
|
|
Treasury Stock
|
|
Retained Earnings
|
|
|
|||||||||||||||||||||
|
Shares
|
|
Amount
|
|
|
Shares
|
|
Amount
|
|
|
|
||||||||||||||||||
Balances, January 1, 2009
|
62,465,572
|
|
|
$
|
625
|
|
|
$
|
141,283
|
|
|
(176,987
|
)
|
|
$
|
(1,892
|
)
|
|
$
|
957,200
|
|
|
$
|
65,293
|
|
|
$
|
1,162,509
|
|
Comprehensive loss, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(99,370
|
)
|
|
—
|
|
|
(99,370
|
)
|
||||||
Change in derivative instrument fair value
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(35,977
|
)
|
|
(35,977
|
)
|
||||||
Reclassification to earnings
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(67,344
|
)
|
|
(67,344
|
)
|
||||||
Pension liability adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
74
|
|
|
74
|
|
||||||
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(202,617
|
)
|
|||||||||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,247
|
)
|
|
—
|
|
|
(6,247
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
86,308
|
|
|
1
|
|
|
1,515
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,516
|
|
||||||
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings, including income tax cost of RSUs
|
156,252
|
|
|
1
|
|
|
(1,951
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,950
|
)
|
||||||
Sale of common stock, including income tax benefit of stock option exercises
|
189,740
|
|
|
2
|
|
|
1,592
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,594
|
|
||||||
Stock-based compensation expense
|
1,250
|
|
|
—
|
|
|
18,077
|
|
|
50,094
|
|
|
688
|
|
|
—
|
|
|
—
|
|
|
18,765
|
|
||||||
Balances, December 31, 2009
|
62,899,122
|
|
|
$
|
629
|
|
|
$
|
160,516
|
|
|
(126,893
|
)
|
|
$
|
(1,204
|
)
|
|
$
|
851,583
|
|
|
$
|
(37,954
|
)
|
|
$
|
973,570
|
|
Comprehensive income, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
196,837
|
|
|
—
|
|
|
196,837
|
|
||||||
Change in derivative instrument fair value
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16,811
|
|
|
16,811
|
|
||||||
Reclassification to earnings
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,641
|
|
|
6,641
|
|
||||||
Pension liability adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(980
|
)
|
|
(980
|
)
|
||||||
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
219,309
|
|
|||||||||||||
Cash dividends, $ 0.10 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,297
|
)
|
|
—
|
|
|
(6,297
|
)
|
||||||
Issuance of common stock under Employee Stock Purchase Plan
|
52,948
|
|
|
1
|
|
|
1,669
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,670
|
|
||||||
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings, including income tax cost of RSUs
|
113,103
|
|
|
1
|
|
|
(2,094
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,093
|
)
|
||||||
Sale of common stock, including income tax benefit of stock option exercises
|
346,377
|
|
|
3
|
|
|
5,621
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,624
|
|
||||||
Stock-based compensation expense
|
1,250
|
|
|
—
|
|
|
25,962
|
|
|
24,258
|
|
|
781
|
|
|
—
|
|
|
—
|
|
|
26,743
|
|
||||||
Balances, December 31, 2010
|
63,412,800
|
|
|
$
|
634
|
|
|
$
|
191,674
|
|
|
(102,635
|
)
|
|
$
|
(423
|
)
|
|
$
|
1,042,123
|
|
|
$
|
(15,482
|
)
|
|
$
|
1,218,526
|
|
Comprehensive income, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
215,416
|
|
|
—
|
|
|
215,416
|
|
||||||
Reclassification to earnings
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,997
|
|
|
12,997
|
|
||||||
Pension liability adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,795
|
)
|
|
(1,795
|
)
|
||||||
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
226,618
|
|
|||||||||||||
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
|
)
|
||||||
Sale of common stock, including income tax benefit of 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
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
215,416
|
|
|
$
|
196,837
|
|
|
$
|
(99,370
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Gain on divestiture activity
|
(220,676
|
)
|
|
(155,277
|
)
|
|
(11,444
|
)
|
|||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
511,103
|
|
|
336,141
|
|
|
304,201
|
|
|||
Exploratory dry hole expense
|
277
|
|
|
289
|
|
|
7,810
|
|
|||
Impairment of proved properties
|
219,037
|
|
|
6,127
|
|
|
174,813
|
|
|||
Abandonment and impairment of unproved properties
|
7,367
|
|
|
1,986
|
|
|
45,447
|
|
|||
Impairment of materials inventory
|
—
|
|
|
—
|
|
|
14,223
|
|
|||
Stock-based compensation expense
|
26,824
|
|
|
26,743
|
|
|
18,765
|
|
|||
Bad debt recovery
|
—
|
|
|
—
|
|
|
(5,189
|
)
|
|||
Change in Net Profits Plan liability
|
(25,477
|
)
|
|
(34,441
|
)
|
|
(7,075
|
)
|
|||
Unrealized derivative (gain) loss
|
(62,757
|
)
|
|
8,899
|
|
|
20,469
|
|
|||
Loss related to hurricanes
|
—
|
|
|
—
|
|
|
8,301
|
|
|||
Amortization of debt discount and deferred financing costs
|
18,299
|
|
|
13,464
|
|
|
12,213
|
|
|||
Deferred income taxes
|
123,789
|
|
|
114,517
|
|
|
(39,735
|
)
|
|||
Plugging and abandonment
|
(5,849
|
)
|
|
(8,314
|
)
|
|
(26,396
|
)
|
|||
Other
|
(6,027
|
)
|
|
(3,993
|
)
|
|
3,382
|
|
|||
Changes in current assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
(41,998
|
)
|
|
(47,153
|
)
|
|
46,743
|
|
|||
Refundable income taxes
|
2,901
|
|
|
24,291
|
|
|
(19,612
|
)
|
|||
Prepaid expenses and other
|
16,376
|
|
|
(35,363
|
)
|
|
(6,626
|
)
|
|||
Accounts payable and accrued expenses
|
(18,073
|
)
|
|
53,198
|
|
|
(4,814
|
)
|
|||
Excess income tax benefit from the exercise of stock awards
|
—
|
|
|
(854
|
)
|
|
—
|
|
|||
Net cash provided by operating activities
|
760,532
|
|
|
497,097
|
|
|
436,106
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Net proceeds from sale of oil and gas properties
|
364,522
|
|
|
311,504
|
|
|
39,898
|
|
|||
Proceeds from insurance settlement
|
—
|
|
|
—
|
|
|
16,789
|
|
|||
Capital expenditures
|
(1,633,093
|
)
|
|
(668,288
|
)
|
|
(379,253
|
)
|
|||
Acquisition of oil and gas properties
|
—
|
|
|
(664
|
)
|
|
(76
|
)
|
|||
Receipts from restricted cash related to 1031 exchange
|
—
|
|
|
—
|
|
|
14,398
|
|
|||
Other
|
3,661
|
|
|
(4,125
|
)
|
|
4,152
|
|
|||
Net cash used in investing activities
|
(1,264,910
|
)
|
|
(361,573
|
)
|
|
(304,092
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from credit facility
|
322,000
|
|
|
571,559
|
|
|
2,072,500
|
|
|||
Repayment of credit facility
|
(370,000
|
)
|
|
(711,559
|
)
|
|
(2,184,500
|
)
|
|||
Debt issuance costs related to credit facility
|
(8,719
|
)
|
|
—
|
|
|
(11,074
|
)
|
|||
Net proceeds from 6.625% Senior Notes
|
341,122
|
|
|
—
|
|
|
—
|
|
|||
Net proceeds from 6.50% Senior Notes
|
343,120
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from sale of common stock
|
7,327
|
|
|
6,440
|
|
|
3,110
|
|
|||
Dividends paid
|
(6,382
|
)
|
|
(6,297
|
)
|
|
(6,247
|
)
|
|||
Excess income tax benefit from the exercise of stock awards
|
—
|
|
|
854
|
|
|
—
|
|
|||
Other
|
(9,973
|
)
|
|
(2,093
|
)
|
|
(1,285
|
)
|
|||
Net cash provided by (used in) financing activities
|
618,495
|
|
|
(141,096
|
)
|
|
(127,496
|
)
|
|||
|
|
|
|
|
|
||||||
Net change in cash and cash equivalents
|
114,117
|
|
|
(5,572
|
)
|
|
4,518
|
|
|||
Cash and cash equivalents at beginning of period
|
5,077
|
|
|
10,649
|
|
|
6,131
|
|
|||
Cash and cash equivalents at end of period
|
$
|
119,194
|
|
|
$
|
5,077
|
|
|
$
|
10,649
|
|
|
For the Years Ended
December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Cash paid for interest, net of capitalized interest
|
$
|
(22,133
|
)
|
|
$
|
(13,340
|
)
|
|
$
|
(17,884
|
)
|
|
|
|
|
|
|
||||||
Net cash refunded for income taxes
|
$
|
4,046
|
|
|
$
|
25,578
|
|
|
$
|
9,857
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands, except per share amounts)
|
||||||||||
Net income (loss)
|
$
|
215,416
|
|
|
$
|
196,837
|
|
|
$
|
(99,370
|
)
|
Basic weighted-average common shares outstanding
|
63,755
|
|
|
62,969
|
|
|
62,457
|
|
|||
Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs
|
2,592
|
|
|
1,720
|
|
|
—
|
|
|||
Add: dilutive effect of 3.50% Senior Convertible Notes
|
1,217
|
|
|
—
|
|
|
—
|
|
|||
Diluted weighted-average common shares outstanding
|
67,564
|
|
|
64,689
|
|
|
62,457
|
|
|||
Basic net income (loss) per common share
|
$
|
3.38
|
|
|
$
|
3.13
|
|
|
$
|
(1.59
|
)
|
Diluted net income (loss) per common share
|
$
|
3.19
|
|
|
$
|
3.04
|
|
|
$
|
(1.59
|
)
|
|
Change in Derivative Instrument Fair Value
|
|
Derivative Reclassification to Earnings
|
|
Pension Liability Adjustments
|
||||||
|
(in thousands)
|
||||||||||
For the year ended December 31, 2009
|
|
|
|
|
|
||||||
Before tax income (loss)
|
$
|
(57,613
|
)
|
|
$
|
(108,071
|
)
|
|
$
|
119
|
|
Tax benefit (expense)
|
21,636
|
|
|
40,727
|
|
|
(45
|
)
|
|||
Income (loss), net of tax
|
$
|
(35,977
|
)
|
|
$
|
(67,344
|
)
|
|
$
|
74
|
|
For the year ended December 31, 2010
|
|
|
|
|
|
||||||
Before tax income (loss)
|
$
|
26,904
|
|
|
$
|
10,608
|
|
|
$
|
(1,570
|
)
|
Tax benefit (expense)
|
(10,093
|
)
|
|
(3,967
|
)
|
|
590
|
|
|||
Income (loss), net of tax
|
$
|
16,811
|
|
|
$
|
6,641
|
|
|
$
|
(980
|
)
|
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
|
)
|
|
As of December 31,
|
||||||
|
2011
|
|
2010
|
||||
|
(in thousands)
|
||||||
Accrued oil, gas, and NGL sales
|
$
|
149,384
|
|
|
$
|
108,393
|
|
Due from joint interest owners
|
30,784
|
|
|
50,018
|
|
||
State severance tax refunds
|
14,979
|
|
|
2,114
|
|
||
Other
|
15,221
|
|
|
2,665
|
|
||
Total accounts receivable
|
$
|
210,368
|
|
|
$
|
163,190
|
|
|
As of December 31,
|
||||||
|
2011
|
|
2010
|
||||
|
(in thousands)
|
||||||
Accrued drilling costs
|
$
|
189,749
|
|
|
$
|
241,298
|
|
Revenue and severance tax payable
|
61,613
|
|
|
37,066
|
|
||
Accrued lease operating expense
|
25,197
|
|
|
17,643
|
|
||
Joint owner advances
|
79,138
|
|
|
24,698
|
|
||
Accrued compensation
|
43,056
|
|
|
45,235
|
|
||
ARO liability
|
7,462
|
|
|
11,679
|
|
||
Accrued interest payable
|
14,646
|
|
|
2,582
|
|
||
Other
|
36,138
|
|
|
37,453
|
|
||
Total accounts payable and accrued expenses
|
$
|
456,999
|
|
|
$
|
417,654
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2011
|
|
2010
|
|
2009
|
||||||
|
|
(in thousands)
|
||||||||||
Current portion of income tax (expense) benefit
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
1,757
|
|
|
$
|
(2,903
|
)
|
|
$
|
21,926
|
|
State
|
|
(1,553
|
)
|
|
(639
|
)
|
|
(1,567
|
)
|
|||
Deferred portion of income tax (expense) benefit
|
|
(123,789
|
)
|
|
(114,517
|
)
|
|
39,735
|
|
|||
Total income tax (expense) benefit
|
|
$
|
(123,585
|
)
|
|
$
|
(118,059
|
)
|
|
$
|
60,094
|
|
Effective tax rate
|
|
36.5
|
%
|
|
37.5
|
%
|
|
37.7
|
%
|
|
|
As of December 31,
|
||||||
|
|
2011
|
|
2010
|
||||
|
|
(in thousands)
|
||||||
Deferred tax liabilities:
|
|
|
|
|
||||
Oil and gas properties
|
|
$
|
639,485
|
|
|
$
|
528,652
|
|
Unrealized derivative asset
|
|
13,274
|
|
|
—
|
|
||
Interest on 3.50% Senior Convertible Notes
|
|
2,256
|
|
|
2,219
|
|
||
Other
|
|
1,873
|
|
|
2,723
|
|
||
Total deferred tax liabilities
|
|
656,888
|
|
|
533,594
|
|
||
Deferred tax assets:
|
|
|
|
|
|
|
||
Net Profits Plan liability
|
|
40,148
|
|
|
50,922
|
|
||
Stock compensation
|
|
17,728
|
|
|
13,143
|
|
||
Federal and state tax net operating loss carryovers
|
|
23,651
|
|
|
10,772
|
|
||
Federal and state tax credit carryovers
|
|
4,301
|
|
|
—
|
|
||
Unrealized derivative liability
|
|
—
|
|
|
6,929
|
|
||
Other long-term liabilities
|
|
10,810
|
|
|
19,740
|
|
||
Total deferred tax assets
|
|
96,638
|
|
|
101,506
|
|
||
Valuation allowance
|
|
(3,791
|
)
|
|
(2,164
|
)
|
||
Net deferred tax assets
|
|
92,847
|
|
|
99,342
|
|
||
Total net deferred tax liabilities
|
|
564,041
|
|
|
434,252
|
|
||
Less: current deferred income tax liabilities
|
|
(3,307
|
)
|
|
(2,710
|
)
|
||
Add: current deferred income tax assets
|
|
7,529
|
|
|
11,593
|
|
||
Non-current net deferred tax liabilities
|
|
$
|
568,263
|
|
|
$
|
443,135
|
|
Current federal income tax refundable
|
|
$
|
5,581
|
|
|
$
|
8,482
|
|
Current state income tax payable
|
|
$
|
774
|
|
|
$
|
294
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Federal statutory tax (expense) benefit
|
$
|
(118,652
|
)
|
|
$
|
(110,214
|
)
|
|
$
|
55,812
|
|
(Increase) decrease in tax resulting from:
|
|
|
|
|
|
|
|
|
|||
State tax (expense) benefit (net of federal benefit)
|
(6,458
|
)
|
|
(7,750
|
)
|
|
5,141
|
|
|||
Research and development credit
|
4,516
|
|
|
—
|
|
|
—
|
|
|||
Change in valuation allowance
|
(1,627
|
)
|
|
1,039
|
|
|
(56
|
)
|
|||
Statutory depletion
|
341
|
|
|
266
|
|
|
189
|
|
|||
Other
|
(1,705
|
)
|
|
(1,400
|
)
|
|
(992
|
)
|
|||
Income tax (expense) benefit
|
$
|
(123,585
|
)
|
|
$
|
(118,059
|
)
|
|
$
|
60,094
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
807
|
|
|
$
|
884
|
|
|
$
|
994
|
|
Additions based on tax positions related to current year
|
1,172
|
|
|
—
|
|
|
—
|
|
|||
Additions for tax positions of prior years
|
183
|
|
|
244
|
|
|
231
|
|
|||
Reductions for lapse of statute of limitations
|
(201
|
)
|
|
(321
|
)
|
|
(341
|
)
|
|||
Ending balance
|
$
|
1,961
|
|
|
$
|
807
|
|
|
$
|
884
|
|
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
|
%
|
2015
|
103.313
|
%
|
2016
|
101.656
|
%
|
2017 and thereafter
|
100.000
|
%
|
Years Ending December 31,
|
|
(in thousands)
|
||
|
|
|
||
2012
|
|
$
|
131,021
|
|
2013
|
|
99,633
|
|
|
2014
|
|
108,629
|
|
|
2015
|
|
97,401
|
|
|
2016
|
|
100,635
|
|
|
Thereafter
|
|
561,642
|
|
|
Total
|
|
$
|
1,098,961
|
|
|
2011
|
|
2010
|
|
2009
|
|||||||||||||||
|
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)
|
1,110,666
|
|
|
$
|
39.48
|
|
|
1,069,090
|
|
|
$
|
32.52
|
|
|
464,333
|
|
|
$
|
26.48
|
|
Granted
(1)
|
266,282
|
|
|
$
|
91.45
|
|
|
387,651
|
|
|
$
|
52.35
|
|
|
725,092
|
|
|
$
|
35.59
|
|
Vested
(1)
|
(364,172
|
)
|
|
$
|
35.74
|
|
|
(210,801
|
)
|
|
$
|
31.18
|
|
|
(76,781
|
)
|
|
$
|
27.20
|
|
Forfeited
(1)
|
(126,882
|
)
|
|
$
|
33.32
|
|
|
(135,274
|
)
|
|
$
|
34.28
|
|
|
(43,554
|
)
|
|
$
|
28.62
|
|
Non-vested at end of year
(1)
|
885,894
|
|
|
$
|
57.52
|
|
|
1,110,666
|
|
|
$
|
39.48
|
|
|
1,069,090
|
|
|
$
|
32.52
|
|
(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
.
|
|
2011
|
|
2010
|
|
2009
|
|||||||||||||||
|
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
|
333,359
|
|
|
$
|
31.16
|
|
|
407,123
|
|
|
$
|
34.67
|
|
|
402,297
|
|
|
$
|
48.24
|
|
Granted
|
98,952
|
|
|
$
|
72.69
|
|
|
128,865
|
|
|
$
|
40.31
|
|
|
241,745
|
|
|
$
|
23.87
|
|
Vested
|
(105,820
|
)
|
|
$
|
30.61
|
|
|
(160,398
|
)
|
|
$
|
46.30
|
|
|
(211,092
|
)
|
|
$
|
46.26
|
|
Forfeited
|
(17,614
|
)
|
|
$
|
36.80
|
|
|
(42,231
|
)
|
|
$
|
35.43
|
|
|
(25,827
|
)
|
|
$
|
50.35
|
|
Non-vested at end of year
|
308,877
|
|
|
$
|
44.33
|
|
|
333,359
|
|
|
$
|
31.16
|
|
|
407,123
|
|
|
$
|
34.67
|
|
|
|
|
Weighted -
|
|
|
|||||
|
|
|
Average
|
|
Aggregate
|
|||||
|
|
|
Exercise
|
|
Intrinsic
|
|||||
|
Shares
|
|
Price
|
|
Value
|
|||||
For the year ended December 31, 2009
|
|
|
|
|
|
|||||
Outstanding, start of year
|
1,509,710
|
|
|
$
|
12.69
|
|
|
|
||
Exercised
|
(189,740
|
)
|
|
$
|
8.40
|
|
|
4,625,148
|
|
|
Forfeited
|
(45,050
|
)
|
|
$
|
13.38
|
|
|
|
||
Outstanding, end of year
|
1,274,920
|
|
|
$
|
13.31
|
|
|
$
|
26,684,106
|
|
Vested and exercisable at end of year
|
1,274,920
|
|
|
$
|
13.31
|
|
|
$
|
26,684,106
|
|
For the year ended December 31, 2010
|
|
|
|
|
|
|||||
Outstanding, start of year
|
1,274,920
|
|
|
$
|
13.31
|
|
|
|
||
Exercised
|
(346,377
|
)
|
|
$
|
13.77
|
|
|
11,281,865
|
|
|
Forfeited
|
(7,778
|
)
|
|
$
|
16.66
|
|
|
|
||
Outstanding, end of year
|
920,765
|
|
|
$
|
13.11
|
|
|
$
|
42,192,057
|
|
Vested and exercisable at end of year
|
920,765
|
|
|
$
|
13.11
|
|
|
$
|
42,192,057
|
|
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
|
|
|
|
|
|
Options Outstanding and Exercisable
|
|||||||||||
|
|
|
|
Number
|
|
Weighted-
|
|
|
|||||||
|
|
|
|
Of Options
|
|
Average
|
|
Weighted-
|
|||||||
|
|
|
|
Outstanding
|
|
Remaining
|
|
Average
|
|||||||
Range of
|
|
and
|
|
Contractual
|
|
Exercise
|
|||||||||
Exercise Prices
|
|
Exercisable
|
|
Life
|
|
Price
|
|||||||||
$
|
10.86
|
|
-
|
$
|
11.95
|
|
|
35,964
|
|
|
0.66 years
|
|
$
|
11.76
|
|
12.03
|
|
-
|
12.03
|
|
|
29,043
|
|
|
0.50 years
|
|
12.03
|
|
|||
12.08
|
|
-
|
12.08
|
|
|
13,080
|
|
|
0.39 years
|
|
12.08
|
|
|||
12.50
|
|
-
|
12.50
|
|
|
80,261
|
|
|
1.0 years
|
|
12.50
|
|
|||
12.53
|
|
-
|
12.53
|
|
|
43,001
|
|
|
1.3 years
|
|
12.53
|
|
|||
12.66
|
|
-
|
12.66
|
|
|
48,055
|
|
|
1.8 years
|
|
12.66
|
|
|||
13.39
|
|
-
|
13.39
|
|
|
21,051
|
|
|
1.8 years
|
|
13.39
|
|
|||
13.65
|
|
-
|
13.65
|
|
|
54,189
|
|
|
1.5 years
|
|
13.65
|
|
|||
14.25
|
|
-
|
14.25
|
|
|
134,710
|
|
|
2.0 years
|
|
14.25
|
|
|||
20.87
|
|
-
|
20.87
|
|
|
48,860
|
|
|
3.0 years
|
|
20.87
|
|
|||
Total
|
|
|
|
508,214
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|||||||
|
2011
|
|
2010
|
|
2009
|
|||
Risk free interest rate
|
0.2
|
%
|
|
0.2
|
%
|
|
0.3
|
%
|
Dividend yield
|
0.2
|
%
|
|
0.3
|
%
|
|
0.5
|
%
|
Volatility factor of the expected market
|
|
|
|
|
|
|||
price of the Company’s common stock
|
36.3
|
%
|
|
46.3
|
%
|
|
95.1
|
%
|
Expected life (in years)
|
0.5
|
|
|
0.5
|
|
|
0.5
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
General and administrative expense
|
$
|
19,326
|
|
|
$
|
19,798
|
|
|
$
|
18,399
|
|
Exploration expense
|
2,091
|
|
|
2,633
|
|
|
1,463
|
|
|||
Total
|
$
|
21,417
|
|
|
$
|
22,431
|
|
|
$
|
19,862
|
|
|
For the Years Ended December 31,
|
||||||
|
2011
|
|
2010
|
||||
|
(in thousands)
|
||||||
Change in benefit obligations
|
|
|
|
||||
Projected benefit obligation at beginning of year
|
$
|
23,867
|
|
|
$
|
18,550
|
|
Service cost
|
3,800
|
|
|
3,392
|
|
||
Interest cost
|
1,184
|
|
|
1,120
|
|
||
Amendments
|
170
|
|
|
—
|
|
||
Actuarial loss
|
1,957
|
|
|
2,480
|
|
||
Benefits paid
|
(1,498
|
)
|
|
(1,675
|
)
|
||
Projected benefit obligation at end of year
|
$
|
29,480
|
|
|
$
|
23,867
|
|
Change in plan assets
|
|
|
|
||||
Fair value of plan assets at beginning of year
|
$
|
10,332
|
|
|
$
|
9,101
|
|
Actual return on plan assets
|
(176
|
)
|
|
1,181
|
|
||
Employer contribution
|
5,260
|
|
|
1,725
|
|
||
Benefits paid
|
(1,476
|
)
|
|
(1,675
|
)
|
||
Fair value of plan assets at end of year
|
$
|
13,940
|
|
|
$
|
10,332
|
|
Funded status at end of year
|
$
|
(15,540
|
)
|
|
$
|
(13,535
|
)
|
|
As of December 31,
|
||||||
|
2011
|
|
2010
|
||||
|
(in thousands)
|
||||||
Projected benefit obligation
|
$
|
29,480
|
|
|
$
|
23,867
|
|
|
|
|
|
||||
Accumulated benefit obligation
|
$
|
21,697
|
|
|
$
|
17,457
|
|
Less: Fair value of plan assets
|
13,940
|
|
|
10,332
|
|
||
Underfunded accumulated benefit obligation
|
$
|
7,757
|
|
|
$
|
7,125
|
|
|
As of December 31,
|
||||||
|
2011
|
|
2010
|
||||
|
(in thousands)
|
||||||
Unrecognized actuarial losses
|
$
|
8,501
|
|
|
$
|
(5,892
|
)
|
Unrecognized prior service costs
|
170
|
|
|
—
|
|
||
Unrecognized transition obligation
|
—
|
|
|
—
|
|
||
Accumulated other comprehensive loss
|
$
|
8,671
|
|
|
$
|
(5,892
|
)
|
|
As of December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Net actuarial gain (loss)
|
$
|
(3,014
|
)
|
|
$
|
(1,937
|
)
|
|
$
|
(239
|
)
|
Prior service cost
|
(170
|
)
|
|
—
|
|
|
—
|
|
|||
Less: Amortization of:
|
|
|
|
|
|
||||||
Actuarial loss
|
(405
|
)
|
|
(367
|
)
|
|
(358
|
)
|
|||
Total other comprehensive income (loss)
|
$
|
(2,779
|
)
|
|
$
|
(1,570
|
)
|
|
$
|
119
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Components of net periodic benefit cost
|
|
|
|
|
|
||||||
Service cost
|
$
|
3,800
|
|
|
$
|
3,392
|
|
|
$
|
2,500
|
|
Interest cost
|
1,184
|
|
|
1,120
|
|
|
934
|
|
|||
Expected return on plan assets that reduces periodic pension cost
|
(880
|
)
|
|
(638
|
)
|
|
(430
|
)
|
|||
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|||
Amortization of net actuarial loss
|
405
|
|
|
367
|
|
|
372
|
|
|||
Net periodic benefit cost
|
$
|
4,509
|
|
|
$
|
4,241
|
|
|
$
|
3,376
|
|
|
As of December 31,
|
||||
|
2011
|
|
2010
|
|
2009
|
Projected benefit obligation
|
|
|
|
|
|
Discount rate
|
4.7%
|
|
5.3%
|
|
6.1%
|
Rate of compensation increase
|
6.2%
|
|
6.2%
|
|
6.2%
|
Net periodic benefit cost
|
|
|
|
|
|
Discount rate
|
5.3%
|
|
6.1%
|
|
6.1%
|
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
|
2012
|
|
2011
|
|
2010
|
|||
Equity securities
|
60.0
|
%
|
|
61.8
|
%
|
|
60.8
|
%
|
Debt securities
|
40.0
|
%
|
|
37.7
|
%
|
|
39.2
|
%
|
Other
|
—
|
%
|
|
0.5
|
%
|
|
—
|
%
|
Total
|
100.0
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
Assets:
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||
|
|
(in thousands)
|
||||||||
Cash and Money Market Funds
|
|
$
|
66
|
|
|
—
|
|
|
—
|
|
Equity Securities
|
|
|
|
|
|
|
||||
Foreign Large Blend (1)
|
|
2,048
|
|
|
—
|
|
|
—
|
|
|
U.S. Small Blend (2)
|
|
2,290
|
|
|
—
|
|
|
—
|
|
|
U.S. Large Blend (3)
|
|
4,278
|
|
|
—
|
|
|
—
|
|
|
Fixed Income Securities
|
|
|
|
|
|
|
||||
Intermediate Term Bond (4)
|
|
5,258
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
$
|
13,940
|
|
|
—
|
|
|
—
|
|
(1)
|
International equities are invested in companies that trade on active exchanges outside the U.S. and are well diversified among a dozen or more developed markets. Active and passive strategies are employed.
|
(2)
|
U.S. equities are invested in companies that are well diversified by industry sector and equity style, such as growth and value strategies, that trade on active exchanges within the U.S. Active and passive management strategies are employed. At least
80%
of this fund is invested in equity securities of small companies.
|
(3)
|
U.S. equities include companies that are well diversified by industry sector and equity style, such as growth and value strategies, that trade on active exchanges within the U.S. Active and passive management strategies are employed. At least
80%
of this fund is invested in equity securities designed to replicate the holdings and weightings of the stocks listed in the S&P 500 index.
|
(4)
|
Intermediate term bonds seek total return. At least
80%
of this fund is invested in a diversified portfolio of bonds, which include all types of securities. It invests primarily in bonds of corporate and governmental issues located in the U.S. and foreign countries, including emerging markets all of which trade on active exchanges.
|
Assets:
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
|
(in thousands)
|
||||||||||
Cash and Money Market Funds
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity Securities
|
|
|
|
|
|
|
||||||
Foreign Large Blend (1)
|
|
1,444
|
|
|
—
|
|
|
—
|
|
|||
U.S. Small Blend (2)
|
|
1,647
|
|
|
—
|
|
|
—
|
|
|||
U.S. Large Blend (3)
|
|
3,185
|
|
|
—
|
|
|
—
|
|
|||
Fixed Income Securities
|
|
|
|
|
|
|
||||||
Intermediate Term Bond (4)
|
|
4,052
|
|
|
—
|
|
|
—
|
|
|||
Total
|
|
$
|
10,332
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Years Ending December 31,
|
|
||
2012
|
$
|
1,296
|
|
2013
|
2,360
|
|
|
2014
|
2,513
|
|
|
2015
|
2,205
|
|
|
2016
|
2,668
|
|
|
2017 through 2021
|
$
|
23,258
|
|
|
As of December 31,
|
||||||
|
2011
|
|
2010
|
||||
|
(in thousands)
|
||||||
Beginning asset retirement obligation
|
$
|
82,849
|
|
|
$
|
102,080
|
|
Liabilities incurred
|
5,465
|
|
|
4,738
|
|
||
Liabilities settled
|
(8,365
|
)
|
|
(30,523
|
)
|
||
Accretion expense
|
5,948
|
|
|
5,583
|
|
||
Revision to estimated cash flows
|
10,009
|
|
|
971
|
|
||
Ending asset retirement obligation
|
$
|
95,906
|
|
|
$
|
82,849
|
|
|
As of December 31, 2011
|
||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
||||
|
(in thousands)
|
||||||||||
Commodity Contracts
|
Current Assets
|
|
$
|
55,813
|
|
|
Current Liabilities
|
|
$
|
42,806
|
|
Commodity Contracts
|
Noncurrent Assets
|
|
31,062
|
|
|
Noncurrent liabilities
|
|
12,875
|
|
||
Derivatives not designated as hedging instruments
|
|
|
$
|
86,875
|
|
|
|
|
$
|
55,681
|
|
|
As of December 31, 2010
|
||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
||||
|
(in thousands)
|
||||||||||
Commodity Contracts
|
Current Assets
|
|
$
|
43,491
|
|
|
Current Liabilities
|
|
$
|
82,044
|
|
Commodity Contracts
|
Noncurrent Assets
|
|
18,841
|
|
|
Noncurrent Liabilities
|
|
32,557
|
|
||
Derivatives designated as hedging instruments
|
|
|
$
|
62,332
|
|
|
|
|
$
|
114,601
|
|
|
For the year ended December 31, 2011
|
||
|
(in thousands)
|
||
Cash settlement (gain) loss:
|
|
||
Oil contracts
|
$
|
22,633
|
|
Natural gas contracts
|
(10,711
|
)
|
|
NGL contracts
|
13,749
|
|
|
Total cash settlement loss
|
$
|
25,671
|
|
|
|
||
Unrealized (gain) loss on changes in fair value:
|
|
||
Oil contracts
|
$
|
(3,391
|
)
|
Natural gas contracts
|
(64,310
|
)
|
|
NGL contracts
|
4,944
|
|
|
Total net unrealized (gain) on change in fair value
|
$
|
(62,757
|
)
|
Total unrealized and realized derivative (gain) loss
|
$
|
(37,086
|
)
|
|
|
|
Location on
Accompanying
Statements of
Operations
|
|
For the Years Ended December 31,
|
||||||||||
|
Derivatives
|
|
|
2011
|
|
2010
|
|
2009
|
|||||||
|
|
|
|
|
(in thousands)
|
||||||||||
Amount reclassified from
AOCIL to realized hedge (loss) gain
|
Commodity Contracts
|
|
Realized hedge (loss) gain
|
|
$
|
12,997
|
|
|
$
|
6,641
|
|
|
$
|
(67,344
|
)
|
|
Derivatives
|
|
Location on Accompanying Balance Sheets
|
|
For the years ended December 31,
|
||||||
|
|
|
|
|
2010
|
|
2009
|
||||
|
|
|
|
|
(in thousands)
|
||||||
Amount of gain (loss) on derivatives recognized in AOCIL during the period (effective portion)
|
Commodity Contracts
|
|
AOCIL
|
|
$
|
16,811
|
|
|
$
|
(35,977
|
)
|
•
|
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)
|
$
|
—
|
|
|
$
|
86,875
|
|
|
$
|
—
|
|
Proved oil and gas properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
139,992
|
|
Unproved oil and gas properties
(2)
|
—
|
|
|
—
|
|
|
15,809
|
|
|||
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
(1)
|
$
|
—
|
|
|
$
|
55,681
|
|
|
$
|
—
|
|
Net Profits Plan
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
107,731
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivatives
|
$
|
—
|
|
|
$
|
62,332
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivatives
|
$
|
—
|
|
|
$
|
114,601
|
|
|
$
|
—
|
|
Net Profits Plan
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
135,850
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance
|
$
|
135,850
|
|
|
$
|
170,291
|
|
|
$
|
177,366
|
|
Net increase in liability
(1)
|
2,269
|
|
|
14,063
|
|
|
13,511
|
|
|||
Net settlements
(1) (2) (3)
|
(30,388
|
)
|
|
(48,504
|
)
|
|
(20,586
|
)
|
|||
Transfers in (out) of Level 3
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance
|
$
|
107,731
|
|
|
$
|
135,850
|
|
|
$
|
170,291
|
|
(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 Company accrued or made cash payments under the Net Profits Plan relating to divestiture proceeds of
$6.3 million
,
$26.1 million
,
and
$724,000
for the years ended
December 31, 2011
,
2010
, and
2009
respectively.
|
(3)
|
During the first quarter of 2011, the Company elected to cash out several Net Profits Plan pools associated with the acquisition of Nance Petroleum Corporation in 1999, through a
$2.6 million
direct payment. As a result, the Company reduced its Net Profits Plan liability by that amount. There is no impact on the accompanying statements of operations for
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Beginning balance on January 1,
|
$
|
35,862
|
|
|
$
|
34,384
|
|
|
$
|
9,437
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
15,618
|
|
|
35,862
|
|
|
34,384
|
|
|||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
|
(32,880
|
)
|
|
(34,384
|
)
|
|
(7,569
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
—
|
|
|
—
|
|
|
(1,868
|
)
|
|||
Ending balance at December 31,
|
$
|
18,600
|
|
|
$
|
35,862
|
|
|
$
|
34,384
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Exploratory well costs capitalized for one year or less
|
$
|
15,618
|
|
|
$
|
35,862
|
|
|
$
|
34,384
|
|
Exploratory well costs capitalized for more than one year
|
2,982
|
|
|
—
|
|
|
—
|
|
|||
Ending balance at December 31,
|
$
|
18,600
|
|
|
$
|
35,862
|
|
|
$
|
34,384
|
|
Number of projects with exploratory well costs that have been capitalized more than a year
|
2
|
|
|
—
|
|
|
—
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Development costs
|
$
|
1,208,255
|
|
|
$
|
299,308
|
|
|
$
|
213,971
|
|
Facility costs
|
112,372
|
|
|
80,328
|
|
|
9,137
|
|
|||
Exploration costs
|
177,465
|
|
|
443,888
|
|
|
154,122
|
|
|||
Acquisitions
|
|
|
|
|
|
||||||
Proved properties
|
—
|
|
|
664
|
|
|
76
|
|
|||
Leasing activity
|
55,237
|
|
|
53,192
|
|
|
41,677
|
|
|||
Total, including asset retirement obligation
(1)(2)
|
$
|
1,553,329
|
|
|
$
|
877,380
|
|
|
$
|
418,983
|
|
(1)
|
Includes capitalized interest of
$10.8 million
,
$4.3 million
, and
$1.9 million
for the years ended
December 31, 2011
,
2010
, and
2009
, respectively.
|
(2)
|
Includes amounts relating to estimated asset retirement obligations of
$19.3 million
,
$5.8 million
, and
$(805,000)
for the years ended
December 31, 2011
,
2010
, and
2009
, respectively.
|
|
||||||||||||||||||||||||||
|
For the Years Ended December 31,
|
|||||||||||||||||||||||||
|
2011
(1)
|
|
2010
(2)
|
|
2009
(3)
|
|||||||||||||||||||||
|
Oil
|
|
Gas
|
|
NGLs
|
|
Oil or Condensate
|
|
Gas
|
|
NGLs
|
|
Oil or Condensate
|
|
Gas
|
|
NGLs
|
|||||||||
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBbl)
|
|||||||||
Total proved reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of year
|
57.4
|
|
|
640.0
|
|
|
—
|
|
|
53.8
|
|
|
449.5
|
|
|
—
|
|
|
51.4
|
|
|
557.4
|
|
|
—
|
|
Revisions of previous estimate
|
(0.9
|
)
|
|
(76.7
|
)
|
|
15.6
|
|
|
3.1
|
|
|
6.1
|
|
|
—
|
|
|
4.5
|
|
|
(76.8
|
)
|
|
—
|
|
Discoveries and extensions
|
26.9
|
|
|
223.5
|
|
|
17.8
|
|
|
16.2
|
|
|
172.9
|
|
|
—
|
|
|
3.4
|
|
|
51.9
|
|
|
—
|
|
Infill reserves in an existing proved field
|
2.8
|
|
|
14.8
|
|
|
0.5
|
|
|
2.8
|
|
|
97.2
|
|
|
—
|
|
|
1.2
|
|
|
29.9
|
|
|
—
|
|
Sales of
reserves
(4)
|
(6.4
|
)
|
|
(37.3
|
)
|
|
(2.9
|
)
|
|
(12.1
|
)
|
|
(14.0
|
)
|
|
—
|
|
|
(0.4
|
)
|
|
(41.8
|
)
|
|
—
|
|
Purchases of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(8.1
|
)
|
|
(100.3
|
)
|
|
(3.5
|
)
|
|
(6.4
|
)
|
|
(71.9
|
)
|
|
—
|
|
|
(6.3
|
)
|
|
(71.1
|
)
|
|
—
|
|
End of year
(5)
|
71.7
|
|
|
664.0
|
|
|
27.5
|
|
|
57.4
|
|
|
640.0
|
|
|
—
|
|
|
53.8
|
|
|
449.5
|
|
|
—
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of year
|
46.0
|
|
|
411.0
|
|
|
—
|
|
|
48.1
|
|
|
342.0
|
|
|
—
|
|
|
47.1
|
|
|
433.2
|
|
|
—
|
|
End of year
|
50.3
|
|
|
451.2
|
|
|
15.2
|
|
|
46.0
|
|
|
411.0
|
|
|
—
|
|
|
48.1
|
|
|
342.0
|
|
|
—
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of year
|
11.4
|
|
|
229.0
|
|
|
—
|
|
|
5.7
|
|
|
107.5
|
|
|
—
|
|
|
4.3
|
|
|
124.2
|
|
|
—
|
|
End of year
|
21.4
|
|
|
212.8
|
|
|
12.3
|
|
|
11.4
|
|
|
229.0
|
|
|
—
|
|
|
5.7
|
|
|
107.5
|
|
|
—
|
|
(1)
|
Please refer to Part I, Item 1 and 2 and Part II, Item 7 for current year reserve discussion.
|
(2)
|
For the year ended
December 31, 2010
, of the
24.7
BCFE upward revision of previous estimate,
42.6
BCFE and
(17.9)
BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2010, were $79.43 per Bbl and $4.38 per MMBtu for oil and natural gas, respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used in 2009. Performance revisions in 2010 resulted in a net 11.2 BCFE decrease in our estimate of proved reserves. While the Company recognized positive performance revisions in every region on proved developed properties, we had approximately 19.3 BCFE of negative performance revisions related to estimated proved undeveloped reserves in primarily dry gas assets, resulting from lower gas prices and higher well costs on the economics of these assets. The Company added 384.2 BCFE from its drilling program, included in discoveries and extensions and infill reserves, the majority which related to its activity in the Eagle Ford shale in South Texas.
|
(3)
|
For the year ended
December 31, 2009
, of the
49.6
BCFE downward revision of previous estimate,
12.0
BCFE and
(61.6)
BCFE relate to price and performance revisions, respectively. The largest portion of the performance revision related to producing properties in the Company’s Wolfberry tight oil program in the Permian Basin in West Texas. Well performance data collected during 2009 at the Sweetie Peck and Halff East programs that target the Wolfberry interval indicated that these assets were underperforming for year-end 2008 decline forecasts.
|
(4)
|
The Company divested of certain non-core assets during
2011
,
2010
, and
2009
. Please refer to
Note 3 - Divestitures and Assets Held for Sale
for additional information.
|
(5)
|
For the years ended
December 31, 2011
,
2010
, and
2009
, amounts included approximately
175
,
356
, and
370
MMcf respectively, representing the Company’s net underproduced gas balancing position.
|
|
2011
|
|
2010
|
|
2009
|
||||||
|
|
|
|
|
|
||||||
Gas (per Mcf)
|
$
|
4.72
|
|
|
$
|
5.54
|
|
|
$
|
3.82
|
|
Oil (per Bbl)
|
$
|
88.00
|
|
|
$
|
70.60
|
|
|
$
|
53.94
|
|
NGLs (per Bbl)
|
$
|
51.95
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
As of December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Future cash inflows
|
$
|
10,871,281
|
|
|
$
|
7,598,159
|
|
|
$
|
4,620,735
|
|
Future production costs
|
(3,786,887
|
)
|
|
(2,512,091
|
)
|
|
(1,968,096
|
)
|
|||
Future development costs
|
(1,036,352
|
)
|
|
(789,493
|
)
|
|
(387,722
|
)
|
|||
Future income taxes
|
(1,740,394
|
)
|
|
(1,335,576
|
)
|
|
(515,953
|
)
|
|||
Future net cash flows
|
4,307,648
|
|
|
2,960,999
|
|
|
1,748,964
|
|
|||
10 percent annual discount
|
(1,727,608
|
)
|
|
(1,294,632
|
)
|
|
(732,997
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
2,580,040
|
|
|
$
|
1,666,367
|
|
|
$
|
1,015,967
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
|
(in thousands)
|
||||||||||
Standardized measure, beginning of year
|
$
|
1,666,367
|
|
|
$
|
1,015,967
|
|
|
$
|
1,059,069
|
|
Sales of oil, gas, and NGLs produced, net of production costs
|
(1,042,281
|
)
|
|
(641,213
|
)
|
|
(409,153
|
)
|
|||
Net changes in prices and production costs
|
454,646
|
|
|
557,681
|
|
|
154,008
|
|
|||
Extensions, discoveries and other including infill reserves in an existing proved field, net of production costs
|
1,816,640
|
|
|
989,365
|
|
|
166,666
|
|
|||
Sales of reserves in place
|
(369,820
|
)
|
|
(151,315
|
)
|
|
(44,823
|
)
|
|||
Purchase of reserves in place
|
—
|
|
|
804
|
|
|
-
|
|
|||
Development costs incurred during the year
|
49,246
|
|
|
43,900
|
|
|
33,742
|
|
|||
Changes in estimated future development costs
|
(31,410
|
)
|
|
49,531
|
|
|
75,134
|
|
|||
Revisions of previous quantity estimates
|
32,992
|
|
|
66,759
|
|
|
(96,354
|
)
|
|||
Accretion of discount
|
234,433
|
|
|
128,408
|
|
|
126,538
|
|
|||
Net change in income taxes
|
(203,169
|
)
|
|
(409,848
|
)
|
|
(61,801
|
)
|
|||
Changes in timing and other
|
(27,604
|
)
|
|
16,328
|
|
|
12,941
|
|
|||
Standardized measure, end of year
|
$
|
2,580,040
|
|
|
$
|
1,666,367
|
|
|
$
|
1,015,967
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
||||||||
Year Ended December 31, 2011
|
|
|
|
|
|
|
|
||||||||
Total operating revenues
|
$
|
315,329
|
|
|
$
|
377,873
|
|
|
$
|
530,574
|
|
|
$
|
379,542
|
|
Total operating expenses
|
335,301
|
|
|
166,166
|
|
|
157,786
|
|
|
559,681
|
|
||||
Income (loss) from operations
|
$
|
(19,972
|
)
|
|
$
|
211,707
|
|
|
$
|
372,788
|
|
|
$
|
(180,139
|
)
|
Income (loss) before income taxes
|
$
|
(29,558
|
)
|
|
$
|
197,384
|
|
|
$
|
363,443
|
|
|
$
|
(192,268
|
)
|
Net income (loss)
|
$
|
(18,503
|
)
|
|
$
|
124,533
|
|
|
$
|
230,097
|
|
|
$
|
(120,711
|
)
|
Basic net income (loss) per common share
|
$
|
(0.29
|
)
|
|
$
|
1.96
|
|
|
$
|
3.60
|
|
|
$
|
(1.89
|
)
|
Diluted net income (loss) per common share
|
$
|
(0.29
|
)
|
|
$
|
1.86
|
|
|
$
|
3.41
|
|
|
$
|
(1.89
|
)
|
Dividends declared per common share
|
$
|
0.05
|
|
|
$
|
—
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2010
|
|
|
|
|
|
|
|
||||||||
Total operating revenues
|
$
|
360,135
|
|
|
$
|
211,697
|
|
|
$
|
226,884
|
|
|
$
|
294,118
|
|
Total operating expenses
|
152,384
|
|
|
174,908
|
|
|
195,832
|
|
|
230,939
|
|
||||
Income from operations
|
$
|
207,751
|
|
|
$
|
36,789
|
|
|
$
|
31,052
|
|
|
$
|
63,179
|
|
Income before income taxes
|
$
|
201,093
|
|
|
$
|
30,500
|
|
|
$
|
24,798
|
|
|
$
|
58,505
|
|
Net income
|
$
|
126,178
|
|
|
$
|
18,068
|
|
|
$
|
15,452
|
|
|
$
|
37,139
|
|
Basic net income per common share
|
$
|
2.01
|
|
|
$
|
0.29
|
|
|
$
|
0.25
|
|
|
$
|
0.59
|
|
Diluted net income per common share
|
$
|
1.96
|
|
|
$
|
0.28
|
|
|
$
|
0.24
|
|
|
$
|
0.56
|
|
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.
|
Name
|
Age
|
Position
|
|
|
|
Anthony J. Best
|
62
|
Chief Executive Officer and President
|
Javan D. Ottoson
|
53
|
Executive Vice President and Chief Operating Officer
|
A. Wade Pursell
|
46
|
Executive Vice President and Chief Financial Officer
|
David W. Copeland
|
55
|
Senior Vice President, General Counsel and Corporate Secretary
|
Gregory T. Leyendecker
|
54
|
Senior Vice President and Regional Manager
|
Mark D. Mueller
|
47
|
Senior Vice President and Regional Manager
|
Lehman E. Newton, III
|
56
|
Senior Vice President and Regional Manager
|
Paul M. Veatch
|
45
|
Senior Vice President and Regional Manager
|
Mark T. Solomon
|
43
|
Vice President and Controller
|
Dennis A. Zubieta
|
45
|
Vice President – Engineering and Evaluation
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
|
|
(a)
|
|
(b)
|
|
(c)
|
||||
Plan category
|
|
Number of securities to be issued upon exercise of outstanding options, warrants, and rights
|
|
Weighted-average exercise price of outstanding options, warrants, and rights
|
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
|
||||
Equity compensation plans approved by security holders:
|
|
|
|
|
|
|
||||
Equity Incentive Compensation Plan
|
|
|
|
|
|
|
||||
Stock options and incentive stock options
(1)
|
|
508,214
|
|
|
$
|
13.86
|
|
|
|
|
Restricted stock
(1)(3)
|
|
308,877
|
|
|
N/A
|
|
|
|
||
Performance share units
(1)(3)(4)
|
|
1,232,225
|
|
|
N/A
|
|
|
|
||
Total for Equity Incentive Compensation Plan
|
|
2,049,316
|
|
|
$
|
13.86
|
|
|
2,708,822
|
|
Employee Stock Purchase Plan
(2)
|
|
-
|
|
|
-
|
|
|
1,373,969
|
|
|
Equity compensation plans not approved by security holders
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Total for all plans
|
|
2,049,316
|
|
|
$
|
13.86
|
|
|
4,082,791
|
|
(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 and 2010 and each amended plan was approved by stockholders at the respective annual stockholders' meetings. The awards granted in 2011, 2010, and 2009 under the Equity Plan were 386,802, 540,774, and 1,016,931, 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 as of 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 41,358, 52,948, and 86,308 in 2011, 2010, and 2009, 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 $44.33 and $52.38, respectively. Please refer to
Note 7 - Compensation Plan
for additional discussion.
|
(4)
|
The number of awards vested assumes a
one
multiplier. The final number of shares issued may vary depending on the ending
three
-year multiplier, which ranges from
zero
to
two
.
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
Report of Independent Registered Public Accounting Firm
|
|
Consolidated Balance Sheets
|
|
Consolidated Statements of Operations
|
|
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss
)
|
|
Consolidated Statements of Cash Flows
|
|
Notes to Consolidated Financial Statements
|
Exhibit
Number
|
Description
|
|
|
2.1
|
Purchase and Sale Agreement dated December 17, 2009 and effective as of November 1, 2009, between Legacy Reserves Operating LP and St. Mary Land & Exploration Company (filed as Exhibit 2.5 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference)
|
2.2
|
Purchase and Sale Agreement dated January 7, 2010 and effective as of November 1, 2009, between Sequel Energy Partners LP, Bakken Energy Partners, LLC, Three Forks Energy Partners, LLC and St. Mary Land & Exploration Company (filed as Exhibit 2.6 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference)
|
2.3
|
Purchase and Sale Agreement dated June 9, 2011, among SM Energy Company, Statoil Texas Onshore Properties LLC, and Tailsman 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)
|
2.4
|
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)
|
2.5
|
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)
|
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
|
Restated By-Laws of SM Energy Company amended effective as of June 1, 2010 (filed as Exhibit 3.2 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, 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
|
Registration Rights Agreement, dated as of April 4, 2007, among St. Mary Land & Exploration Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wachovia Capital Markets, LLC, for themselves and as representatives of the Initial Purchasers (filed Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on April 4, 2007, and incorporated herein by reference)
|
4.3
|
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)
|
4.4
|
Registration Rights Agreement, dated as of February 7, 2011, by and among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the several initial purchasers (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference)
|
4.5
|
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)
|
4.6
|
Registration Rights Agreement, dated as of November 8, 2011, by and among SM Energy Company and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of several purchasers (filed as Exhibit 4.2 to the registrant's Current Report on Form 8-K filed on November 10, 2011, 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†
|
Form of Performance Share Award Agreement (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and incorporated herein by reference)
|
10.7†
|
Form of Performance Share Award Notice (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and incorporated herein by reference)
|
10.8
|
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)
|
10.9
|
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)
|
10.10†
|
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)
|
10.11†
|
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)
|
10.12
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)
|
10.13†
|
Form of Performance Share and Restricted Stock Unit Award Agreement (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, and incorporated herein by reference)
|
10.14†
|
Form of Performance Share and Restricted Stock Unit Award Notice (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, and incorporated herein by reference)
|
10.15†
|
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)
|
10.16†
|
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)
|
10.17
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)
|
10.18
|
Carry and Earning Agreement between St. Mary Land & Exploration Company and Encana Oil & Gas (USA) Inc. executed as of April 29, 2010 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)
|
10.19†
|
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)
|
10.20†
|
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)
|
10.21†
|
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)
|
10.22***
|
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)
|
10.23
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)
|
10.24
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)
|
10.25
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)
|
10.26†
|
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)
|
10.27†
|
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)
|
10.28
|
Purchase Agreement, dated January 31, 2011, among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers named therein (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on February 1, 2011, and incorporated herein by reference)
|
10.29
|
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)
|
10.30+
|
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)
|
10.31*†
|
Summary of Compensation Arrangements for Non-Employee Directors
|
10.32
|
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)
|
10.33
|
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)
|
10.34
|
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)
|
10.35
|
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)
|
10.36†
|
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)
|
10.37†
|
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)
|
10.38†
|
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)
|
10.39†
|
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)
|
10.40†
|
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)
|
10.41*
|
Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011
|
10.42*
|
Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012
|
12.1*
|
Computation of Ratio of Earnings to Fixed Charges
|
21.1*
|
Subsidiaries of Registrant
|
23.1*
|
Consent of Deloitte & Touche LLP
|
23.2*
|
Consent of Ryder Scott Company L.P.
|
24.1*
|
Power of Attorney
|
31.1*
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
|
31.2*
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
|
32.1**
|
Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002
|
99.1*
|
Ryder Scott Audit Letter
|
101.INS****
|
XBRL Instance Document
|
101.SCH****
|
XBRL Schema Document
|
101.CAL****
|
XBRL Calculation Linkbase Document
|
101.LAB****
|
XBRL Label Linkbase Document
|
101.PRE****
|
XBRL Presentation Linkbase Document
|
101.DEF****
|
XBRL Taxonomy Extension Definition Linkbase Document
|
***
|
Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934.
|
****
|
Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
|
†
|
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 23, 2012
|
By:
|
/s/ ANTHONY J. BEST
|
|
|
|
Anthony J. Best
|
|
|
|
President and Chief Executive Officer
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ ANTHONY J. BEST
|
|
President and Chief Executive Officer
|
|
February 23, 2012
|
Anthony J. Best
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ A. WADE PURSELL
|
|
Executive Vice President and Chief Financial Officer
|
|
February 23, 2012
|
A. Wade Pursell
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ MARK T. SOLOMON
|
|
Vice President and Controller
|
|
February 23, 2012
|
Mark T. Solomon
|
|
|
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ WILLIAM D. SULLIVAN
|
|
Chairman of the Board of Directors
|
|
February 23, 2012
|
William D. Sullivan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ BARBARA M. BAUMANN
|
|
Director
|
|
February 23, 2012
|
Barbara M. Baumann
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ LARRY W. BICKLE
|
|
Director
|
|
February 23, 2012
|
Larry W. Bickle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ STEPHEN R. BRAND
|
|
Director
|
|
February 23, 2012
|
Stephen R. Brand
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ WILLIAM J. GARDINER
|
|
Director
|
|
February 23, 2012
|
William J. Gardiner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ JULIO M. QUINTANA
|
|
Director
|
|
February 23, 2012
|
Julio M. Quintana
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ JOHN M. SEIDL
|
|
Director
|
|
February 23, 2012
|
John M. Seidl
|
|
|
|
|
|
|
|
|
|
•
|
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 2,395 shares of SM Energy common stock issued on May 26, 2011, 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 1,122 shares of SM Energy common stock issued on May 26, 2011, 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, Julio M. Quintana and William D. Sullivan each elected SM Energy common stock for their retainer, which resulted in a grant of 823 shares of SM Energy common stock issued on May 26, 2011, 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 $55,000 cash payment for their retainer.
|
|
Year Ended December 31,
|
||||||||||||||
|
2011
|
2010
|
2009
|
2008
|
2007
|
||||||||||
|
(in thousands, except ratios)
|
||||||||||||||
|
|
|
|
|
|
||||||||||
Pretax income from continuing operations
|
$
|
339,001
|
|
$
|
314,896
|
|
$
|
(159,464
|
)
|
$
|
144,736
|
|
$
|
296,111
|
|
|
|
|
|
|
|
||||||||||
Add: Fixed charges
|
58,030
|
|
29,558
|
|
31,702
|
|
32,604
|
|
31,473
|
|
|||||
Add: Amortization of capitalized interest
|
5,107
|
|
2,991
|
|
2,697
|
|
2,387
|
|
1,768
|
|
|||||
Less: Capitalized interest
|
(10,785
|
)
|
(4,337
|
)
|
(1,902
|
)
|
(4,668
|
)
|
(6,672
|
)
|
|||||
Earnings before fixed charges
|
$
|
391,353
|
|
$
|
343,108
|
|
$
|
(126,967
|
)
|
$
|
175,059
|
|
$
|
322,680
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
||||||||||
Interest expense
(1)
|
45,849
|
|
24,196
|
|
28,856
|
|
26,950
|
|
24,046
|
|
|||||
Capitalized interest
|
10,785
|
|
4,337
|
|
1,902
|
|
4,668
|
|
6,672
|
|
|||||
Interest expense component of rent
(2)
|
1,396
|
|
1,025
|
|
944
|
|
986
|
|
755
|
|
|||||
Total fixed charges
|
$
|
58,030
|
|
$
|
29,558
|
|
$
|
31,702
|
|
$
|
32,604
|
|
$
|
31,473
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
6.7
|
|
11.6
|
|
—
|
|
5.4
|
|
10.3
|
|
|||||
Insufficient coverage
|
$
|
—
|
|
$
|
—
|
|
$
|
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.
|
Wilkinson Pipeline, LLC, a Mississippi limited liability company (24%)
|
3.
|
Trinity River Systems, LTD, a Texas limited partnership (21%)
|
4.
|
1977 H.B Joint Account, a Colorado general partnership (8%)
|
5.
|
1976 H.B Joint Account, a Colorado general partnership (9%)
|
6.
|
1974 H.B Joint Account, a Colorado general partnership (4%)
|
7.
|
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
|
(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
|
(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.
|
Michael F. Stell
|
|
James L. Baird
|
Michael F. Stell
|
|
James L. Baird
|
TBPE License No. 56416
|
|
Managing Senior Vice President
|
Managing Senior Vice President
|
|
|
As of December 31, 2011
|
|
|
Proved
|
||||||||||
|
|
Developed
|
|
|
|
Total
|
||||||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
||||
Net Reserves of Properties
Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
||||
Oil/Condensate - MBarrels
|
|
34,631
|
|
|
815
|
|
|
20,300
|
|
|
55,746
|
|
Plant Products - MBarrels
|
|
13,390
|
|
|
111
|
|
|
12,129
|
|
|
25,631
|
|
Gas - MMCF
|
|
314,558
|
|
|
4,788
|
|
|
190,505
|
|
|
509,851
|
|
|
|
|
|
|
|
|
|
|
||||
Net Reserves of Properties
Not Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
||||
Oil/Condensate - MBarrels
|
|
13,393
|
|
|
1,424
|
|
|
1,144
|
|
|
15,961
|
|
Plant Products - MBarrels
|
|
1,585
|
|
|
117
|
|
|
157
|
|
|
1,859
|
|
Gas - MMCF
|
|
97,122
|
|
|
34,742
|
|
|
22,338
|
|
|
154,202
|
|
|
|
|
|
|
|
|
|
|
||||
Total Net Reserves
|
|
|
|
|
|
|
|
|
||||
Oil/Condensate -MBarrels
|
|
48,024
|
|
|
2,239
|
|
|
21,444
|
|
|
71,707
|
|
Plant Products - MBarrels
|
|
14,975
|
|
|
229
|
|
|
12,286
|
|
|
27,490
|
|
Gas - MMCF
|
|
411,680
|
|
|
39,530
|
|
|
212,843
|
|
|
664,053
|
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not
|
(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.
|