þ | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
o | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
Delaware | 75-2379388 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
601 Poydras, Suite 2400 | ||
New Orleans, LA | 70130 | |
( Address of principal executive offices) | (Zip Code) | |
Registrants telephone number: (504) 587-7374 |
Title of each class: | Name of each exchange on which registered: | |
Common Stock, $.001 Par Value | New York Stock Exchange |
Large accelerated filer þ | Accelerated filer o | Non-accelerated o | Smaller reporting company o | |||
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EX-10.21 | ||||||||
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EX-31.1 | ||||||||
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EX-32.1 | ||||||||
EX-32.2 |
1
2
| changes in competitive prices; | ||
| oil and gas prices and industry perceptions of future prices; | ||
| fluctuations in the level of activity by oil and gas producers; | ||
| changes in the number of liftboats operating in the Gulf of Mexico; | ||
| the ability of oil and gas producers to generate capital; | ||
| general economic conditions; and | ||
| governmental regulation. |
3
| federal, state and international laws and other regulations relating to the oil and gas industry; | ||
| changes in such laws and regulations; and | ||
| the level of enforcement thereof. |
4
5
6
| the level of worldwide oil and gas exploration and production; | ||
| the cost of exploring for, producing and delivering oil and gas; | ||
| demand for energy, which is affected by worldwide economic activity and population growth; | ||
| the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels for oil; | ||
| the discovery rate of new oil and gas reserves; | ||
| political and economic uncertainty, socio-political unrest and regional instability or hostilities; and | ||
| technological advances affecting energy exploration, production and consumption. |
7
| changes in competitive prices; | ||
| fluctuations in the level of activity in major markets; | ||
| an increased number of liftboats in the Gulf of Mexico; | ||
| general economic conditions; and | ||
| governmental regulation. |
| political, social and economic instability; | ||
| potential expropriation, seizure or nationalization of assets; | ||
| increased operating costs; | ||
| social unrest, acts of terrorism, war or other armed conflict; | ||
| renegotiating, cancellation or forced modification of contracts; | ||
| import-export quotas; | ||
| confiscatory taxation or other adverse tax policies; | ||
| currency fluctuations; | ||
| restrictions on the repatriation of funds; | ||
| submission to the jurisdiction of a foreign court or arbitration panel or having to enforce the judgment of a foreign court or arbitration panel against a sovereign nation within its own territory; and | ||
| other forms of government regulation which are beyond our control. |
| the awarding of contracts to local contractors; | ||
| the employment of local citizens; and | ||
| the establishment of foreign subsidiaries with significant ownership positions reserved by the foreign government for local citizens. |
8
9
| fires; | ||
| explosions, blowouts and cratering; | ||
| hurricanes and other extreme weather conditions; | ||
| mechanical problems, including pipe failure; | ||
| abnormally pressured formations; and | ||
| environmental accidents, including oil spills, gas leaks or ruptures, uncontrollable flows of oil, gas, brine or well fluids, or other discharges of toxic gases or other pollutants. |
10
| the presence of unanticipated pressure or irregularities in formations; | ||
| equipment failures or accidents; | ||
| adverse weather conditions; | ||
| compliance with governmental requirements; and | ||
| shortages or delays in obtaining equipment or in the delivery of equipment and services. |
| lack of sufficient executive-level personnel; | ||
| increased administrative burden; and | ||
| increased logistical problems common to large, expansive operations. |
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
High
Low
$
45.14
$
34.90
57.25
40.04
54.42
29.95
30.28
11.64
$
18.37
$
11.52
24.19
12.97
22.86
15.49
25.78
20.14
Table of Contents
Years Ended December 31,
2005
2006
2007
2008
2009
$
137
$
212
$
223
$
103
$
158
$
105
$
121
$
128
$
81
$
102
$
152
$
157
$
213
$
82
$
134
The lines represent monthly index levels derived from compounded daily returns that
include all dividends.
The indexes are reweighted daily, using the market capitalization on the previous
trading day.
If the monthly interval, based on the fiscal year-end, is not a trading day, the
preceding trading day is used.
The index level for all series was set to $100.00 on December 31, 2004.
Table of Contents
Years Ended December 31,
2009
2008
2007
2006
2005
$
1,449,300
$
1,881,124
$
1,572,467
$
1,093,821
$
735,334
(51,384
)
565,692
465,838
316,889
125,603
(102,323
)
351,475
271,558
187,663
67,859
(1.31
)
4.39
3.35
2.35
0.87
(1.31
)
4.33
3.30
2.31
0.85
2,516,665
2,490,145
2,255,295
1,872,067
1,097,250
848,665
654,199
637,789
622,508
216,596
88,158
87,046
107,641
1,178,045
1,254,273
1,025,666
765,237
524,374
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Table of Contents
%
%
2009
Change
2008
Change
2007
1,089
-42
%
1,879
6
%
1,768
997
-8
%
1,079
7
%
1,005
$
62.67
-37
%
$
99.73
38
%
$
72.19
$
4.27
-53
%
$
9.04
4
%
$
8.67
(1)
Estimate of drilling activity as measured by average active drilling
rigs based on Baker Hughes Inc. rig count information.
(2)
Excludes Canadian Rig Count.
Revenue
2009
%
2008
%
Change
$
804,944
56
%
$
1,024,589
54
%
$
(219,645
)
321,127
22
%
539,795
29
%
(218,668
)
323,229
22
%
316,740
17
%
6,489
$
1,449,300
100
%
$
1,881,124
100
%
$
(431,824
)
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Revenue
Cost of Services, Rentals and Sales
2009
2008
Change
2009
%
2008
%
Change
$
919,335
$
1,155,221
$
(235,886
)
$
616,116
67
%
$
633,127
55
%
$
(17,011
)
426,876
550,939
(124,063
)
143,802
34
%
178,563
32
%
(34,761
)
103,089
121,104
(18,015
)
64,116
62
%
74,830
62
%
(10,714
)
55,072
(55,072
)
12,986
24
%
(12,986
)
(1,212
)
1,212
(1,212
)
1,212
$
1,449,300
$
1,881,124
$
(431,824
)
$
824,034
57
%
$
898,294
48
%
$
(74,260
)
Table of Contents
Table of Contents
Revenue
Cost of Services, Rentals and Sales
2008
2007
Change
2008
%
2007
%
Change
$
1,155,221
$
761,015
$
394,206
$
633,127
55
%
$
419,818
55
%
$
213,309
550,939
496,290
54,649
178,563
32
%
156,731
32
%
21,832
121,104
127,898
(6,794
)
74,830
62
%
60,432
47
%
14,398
55,072
192,700
(137,628
)
12,986
24
%
66,580
35
%
(53,594
)
(1,212
)
(5,436
)
4,224
(1,212
)
(5,436
)
4,224
$
1,881,124
$
1,572,467
$
308,657
$
898,294
48
%
$
698,125
44
%
$
200,169
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Table of Contents
during any fiscal quarter (and only during such fiscal quarter), if the last reported
sale price of our common stock is greater than or equal to 135% of the applicable exchange
price of the notes for at least 20 trading days in the period of 30 consecutive trading
days ending on the last trading day of the preceding fiscal quarter;
Table of Contents
prior to December 15, 2011, during the five business-day period after any ten
consecutive trading-day period (the measurement period) in which the trading price of
$1,000 principal amount of notes for each
trading day in the measurement period was less than 95% of the product of the last reported
sale price of our common stock and the exchange rate on such trading day;
if the notes have been called for redemption;
upon the occurrence of specified corporate transactions; or
at any time beginning on September 15, 2026, and ending at the close of business on the
second business day immediately preceding the maturity date of December 15, 2026.
Description
2010
2011
2012
2013
2014
Thereafter
$
37,259
$
209,319
$
27,231
$
27,179
$
316,814
$
474,354
13,191
7,609
4,609
2,654
2,221
14,434
16,647
10,103
6,948
4,544
14,281
$
50,450
$
233,575
$
41,943
$
36,781
$
323,579
$
503,069
Table of Contents
Table of Contents
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Table of Contents
Superior Energy Services, Inc.:
February 26, 2010
Table of Contents
Consolidated Balance Sheets
December 31, 2009 and 2008
(in thousands, except share data)
Table of Contents
Consolidated Statements of Operations
Years Ended December 31, 2009, 2008 and 2007
(in thousands, except per share data)
2009
2008 *
2007 *
$
1,449,300
$
1,826,052
$
1,379,767
55,072
192,700
1,449,300
1,881,124
1,572,467
824,034
885,308
631,545
12,986
66,580
(exclusive of items shown separately below)
824,034
898,294
698,125
207,114
175,500
187,841
259,093
282,584
228,146
212,527
2,084
40,946
7,483
(51,384
)
565,692
465,838
(50,906
)
(46,684
)
(48,436
)
926
2,975
2,662
571
(3,977
)
189
(22,600
)
24,373
(2,940
)
(36,486
)
(159,879
)
542,379
417,313
(57,556
)
190,904
145,755
$
(102,323
)
$
351,475
$
271,558
$
(1.31
)
$
4.39
$
3.35
$
(1.31
)
$
4.33
$
3.30
78,171
79,990
80,973
1,163
1,358
60
58
78,171
81,213
82,389
Table of Contents
Consolidated Statements of Changes in Stockholders Equity
Years Ended December 31, 2009, 2008 and 2007
(in thousands, except share data)
Accumulated
Preferred
Common
Additional
other
stock
Preferred
stock
Common
paid-in
comprehensive
Retained
shares
stock
shares
stock
capital *
income (loss), net
earnings *
Total
$
80,617,337
$
81
$
466,501
$
10,288
$
288,367
$
765,237
271,558
271,558
(2,580
)
(2,580
)
1,370
1,370
(1,210
)
271,558
270,348
840
840
160,234
2,685
2,685
867,916
1
8,439
8,440
9,408
9,408
1,529
1,529
26,163
949
949
(1,000,000
)
(1
)
(33,769
)
(33,770
)
$
80,671,650
$
81
$
456,582
$
9,078
$
559,925
$
1,025,666
351,475
351,475
6,460
6,460
(48,179
)
(48,179
)
(41,719
)
351,475
309,756
840
840
501,112
1
4,685
4,686
426,592
4,274
4,274
5,411
5,411
2,643
2,643
14,559
74,405
2,948
2,948
56,754
1,833
1,833
(3,717,000
)
(4
)
(103,780
)
(103,784
)
$
78,028,072
$
78
$
375,436
$
(32,641
)
$
911,400
$
1,254,273
Table of Contents
Consolidated Statements of Changes in Stockholders Equity (Continued)
Years Ended December 31, 2009, 2008 and 2007
(in thousands, except share data)
Accumulated
Preferred
Common
Additional
other
stock
Preferred
stock
Common
paid-in
comprehensive
Retained
shares
stock
shares
stock
capital
income (loss), net
earnings
Total
$
78,028,072
$
78
$
375,436
$
(32,641
)
$
911,400
$
1,254,273
(102,323
)
(102,323
)
(3,881
)
(3,881
)
17,526
17,526
13,645
(102,323
)
(88,678
)
700
700
305,182
1
5,837
5,838
38,717
375
375
170
170
2,401
2,401
71,392
920
920
133,360
2,308
2,308
(17,373
)
(262
)
(262
)
$
78,559,350
$
79
$
387,885
$
(18,996
)
$
809,077
$
1,178,045
Table of Contents
Consolidated Statements of Cash Flows
Years Ended December 31, 2009, 2008 and 2007
(in thousands)
2009
2008 *
2007 *
$
(102,323
)
$
351,475
$
271,558
207,114
175,500
187,841
(74,704
)
103,504
65,565
212,527
36,486
(170
)
(5,411
)
(9,408
)
11,785
12,182
12,549
1,550
15,255
(189
)
28,606
(7,102
)
2,940
21,744
19,963
18,697
(2,084
)
(40,946
)
(7,483
)
25,609
(77,565
)
(25,361
)
(51,320
)
(184,602
)
4,652
(24,637
)
20,252
(7,036
)
(41,264
)
(5,917
)
7,591
(6,160
)
(2,769
)
(2,301
)
12,434
8,524
29,485
19,497
2,612
276,103
402,359
530,283
(286,277
)
(453,861
)
(410,518
)
(1,247
)
(8,410
)
(110,973
)
(8,000
)
7,716
155,312
18,100
(8,694
)
(3,769
)
(3,578
)
9,280
(292,271
)
(310,537
)
(502,111
)
177,000
(810
)
(810
)
(810
)
(2,308
)
(83
)
375
4,274
8,440
170
5,411
9,408
1,958
1,558
806
(103,784
)
(33,770
)
176,385
(93,351
)
(16,009
)
1,435
(5,267
)
516
161,652
(6,796
)
12,679
44,853
51,649
38,970
$
206,505
$
44,853
$
51,649
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December 31, 2009, 2008 and 2007
(a)
Basis of Presentation
The consolidated financial statements include the accounts of Superior Energy Services,
Inc. and subsidiaries (the Company). All significant intercompany accounts and
transactions are eliminated in consolidation. Certain previously reported amounts have
been reclassified to conform to the 2009 presentation.
(b)
Business
The Company is a leading provider of specialized oilfield services and equipment focusing
on serving the production and drilling related needs of oil and gas companies. The
Company provides most of the services, tools and liftboats necessary to maintain, enhance
and extend producing wells, as well as plug and abandonment services at the end of their
life cycle.
(c)
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make significant estimates
and assumptions that affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates.
(d)
Major Customers and Concentration of Credit Risk
The majority of the Companys business is conducted with major and independent oil and gas
exploration companies. The Company evaluates the financial strength of its customers and
provides allowances for probable credit losses when deemed necessary.
The market for the Companys services and products is the offshore and onshore oil and gas
industry in the United States and select international market areas. Oil and gas
companies make capital expenditures on exploration, drilling and production operations.
The level of these expenditures historically has been characterized by significant
volatility.
The Company derives a large amount of revenue from a small number of major and independent
oil and gas companies. In 2009 and 2008, Chevron accounted for approximately 15% and 12%,
respectively, Apache accounted for approximately 13% and 11%, respectively and BP
accounted for approximately 11% of total revenue primarily related to our subsea and well
enhancement segment. In 2007, Shell accounted for approximately 11% of total revenue,
primarily related to our oil and gas and drilling products and services segments.
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(e)
Cash Equivalents
The Company considers all short-term investments with a maturity of 90 days or less when
purchased to be cash equivalents.
(f)
Accounts Receivable and Allowances
Trade accounts receivable are recorded at the invoiced amount or the earned amount but not
yet invoiced and do not bear interest. The Company maintains allowances for estimated
uncollectible receivables including bad debts and other items. The allowance for doubtful
accounts is based on the Companys best estimate of probable uncollectible amounts in
existing accounts receivable. The Company determines the allowance based on historical
write-off experience and specific identification.
(g)
Other Current Assets
Other current assets include approximately $210.0 million and $168.3 million of costs
incurred and estimated earnings in excess of billings on uncompleted contracts at December
31, 2009 and 2008, respectively. The Company follows the percentage-of-completion method
of accounting for applicable contracts. Accordingly, income is recognized in the ratio
that costs incurred bears to estimated total costs. Adjustments to cost estimates are
made periodically, and losses expected to be incurred on contracts in progress are charged
to operations in the period such losses are determined.
Additionally, other current assets include approximately $38.4 million and $31.5 million
of raw materials and supplies at December 31, 2009 and 2008, respectively. Raw materials
and supplies consist principally of products which are consumed in our services provided
to customers, spare parts and supplies for equipment used in providing these services, and
raw materials used for finished products. These supplies are stated at the lower of cost
or market. Cost primarily represents invoiced costs. Cost is determined on an average cost
basis for all other raw materials and supplies.
(h)
Property, Plant and Equipment
Property, plant and equipment are stated at cost, except for assets acquired using
purchase accounting, which are recorded at fair value as of the date of acquisition. With
the exception of the Companys liftboats and derrick barges, depreciation is computed
using the straight line method over the estimated useful lives of the related assets as
follows:
3 to 40 years
5 to 25 years
2 to 20 years
3 to 10 years
2 to 10 years
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If such assets are considered to be impaired, the impairment to be recognized is measured
by the amount by which the carrying amount of the assets exceeds the fair value. Assets
are grouped by subsidiary or division for the impairment testing, except for liftboats,
which are grouped together by leg length. These groupings represent the lowest level of
identifiable cash flows. The Company has long-lived assets, such as facilities, utilized
by multiple operating divisions that do not have identifiable cash flows. Impairment
testing for these long-lived assets is based on the consolidated entity. Assets to be
disposed of are reported at the lower of the carrying amount or fair value less costs to
sell. For the year ended December 31, 2009, we recorded approximately $119.8 million
reduction in the value of property, plant and equipment due to the decline in the North
American land markets (see note 3).
(i)
Goodwill
The Company accounts for goodwill and other intangible assets in accordance with
Accounting Standards Codification 350-10 (ASC 350-10), Intangibles Goodwill and Other. ASC
350-10 requires that goodwill as well as other intangible assets with indefinite lives no
longer be amortized, but instead tested annually for impairment. To test for impairment
at December 31, 2009, the Company identified its reporting units (which are consistent
with the Companys operating segments) and determined the carrying value of each reporting
unit by assigning the assets and liabilities, including goodwill and intangible assets, to
the reporting units. The Company then estimated the fair value of each reporting unit and
compared it to the reporting units carrying value. Based on this test, the fair values
of the reporting units substantially exceeded the carrying amounts. No impairment loss
was recognized in the years ended December 31, 2009, 2008 or 2007 under this method. The
following table summarizes the activity for the Companys goodwill for the years ended
December 31, 2009 and 2008 (amounts in thousands):
Subsea and
Drilling
Well
Products and
Enhancement
Services
Marine
Total
$
329,692
$
143,740
$
11,162
$
484,594
2,241
1,499
3,740
387
1,075
1,462
(242
)
(11,694
)
(11,936
)
$
332,078
$
134,620
$
11,162
$
477,860
(229
)
(229
)
1,731
1,731
33
3,085
3,118
$
332,111
$
139,436
$
10,933
$
482,480
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(j)
Intangible and Other Long-Term Assets
Intangible and other long-term assets consist of the following at December 31, 2009 and
2008 (amounts in thousands):
December 31, 2009
December 31, 2008
Gross
Accumulated
Net
Gross
Accumulated
Net
Amount
Amortization
Balance
Amount
Amortization
Balance
$
12,826
$
(2,777
)
$
10,049
$
108,811
$
(14,424
)
$
94,387
2,654
(808
)
1,846
15,812
(1,813
)
13,999
1,465
(1,117
)
348
1,705
(1,071
)
634
20,704
(10,237
)
10,467
17,492
(5,865
)
11,627
12,382
12,382
7,212
7,212
13,774
13,774
14,859
14,859
2,412
(309
)
2,103
586
(258
)
328
$
66,217
$
(15,248
)
$
50,969
$
166,477
$
(23,431
)
$
143,046
Customer relationships, tradenames, and non-compete agreements are amortized using the
straight line method over the life of the related asset with weighted average useful lives
of 11 years, 9 years, and 3 years, respectively. Debt acquisition costs are amortized
primarily using the effective interest method over the life of the related debt agreements
with a weighted average useful life of 7 years. Amortization of debt acquisition costs is
recorded in interest expense. Amortization expense (exclusive of debt acquisition costs)
was approximately $4.3 million, $9.1 million and $7.8 million for the years ended December
31, 2009, 2008 and 2007, respectively. Estimated annual amortization of intangible assets
(exclusive of debt acquisition costs) will be approximately $1.7 million for 2010, $1.5
million for 2011 and 2012, and $1.4 million for 2013 and 2014, excluding the effects of
any acquisitions or dispositions subsequent to December 31, 2009.
In connection with the review for impairment of long-lived assets in accordance with
Accounting Standards Codification 360-10 (ASC 360-10), Property, Plant and Equipment,
the Company recorded approximately $92.7 million as a reduction in the value of intangible
assets during the year ended December 31, 2009 (see note 3).
(k)
Decommissioning Liability
Prior to the sale of 75% of its interest in SPN Resources, the Company recorded estimated
future decommissioning liabilities related to its oil and gas producing properties
pursuant to the provisions of Accounting Standards Codification 410-20 (ASC 410-20),
Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of
a liability at estimated present value for an asset retirement obligation (decommissioning
liabilities) in the period in which it is incurred with a corresponding increase in the
carrying amount of the related long-lived asset. Subsequent to initial measurement, the
decommissioning liability was required to be accreted each period to present value.
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The following table summarizes the activity for the Companys decommissioning liability
for the year ended December 31, 2008 (amounts in thousands):
$
124,970
(104,362
)
1,019
(21,627
)
$
(l)
Revenue Recognition
Revenue is recognized when services or equipment are provided. The Company contracts for
marine, subsea and well enhancement projects either on a day rate or turnkey basis, with a
vast majority of its projects conducted on a day rate basis. The Companys drilling
products and services are rented on a day rate basis, and revenue from the sale of
equipment is recognized when the equipment is shipped. Reimbursements from customers for
the cost of drilling products and services that are damaged or lost down-hole are
reflected as revenue at the time of the incident. The Company is accounting for the
revenue and related costs on a large-scale platform decommissioning contract on the
percentage-of-completion method utilizing costs incurred as a percentage of total
estimated costs (see note 5). Prior to the sale of 75% of its interest in SPN Resources,
the Company recognized oil and gas revenue from its interests in producing wells as oil
and natural gas was sold from those wells.
(m)
Taxes Collected from Customers
Pursuant to Accounting Standards Codification 605-45-50-3, Taxes Collected from Customers
and Remitted to Governmental Authorities, the Company elected to net taxes collected from
customers against those remitted to government authorities in the financial statements
consistent with the historical presentation of this information.
(n)
Income Taxes
The Company accounts for income taxes and the related accounts under the asset and
liability method. Deferred income taxes reflect the impact of temporary differences
between amounts of assets and liabilities for financial reporting purposes and such
amounts as measured by tax laws.
(o)
Earnings (loss) per Share
Basic earnings (loss) per share is computed by dividing income (loss) available to common
stockholders by the weighted average number of common shares outstanding during the
period. Diluted earnings per share is computed in the same manner as basic earnings per
share except that the denominator is increased to include the number of additional common
shares that could have been outstanding assuming the exercise of stock options and
restricted stock units and the potential shares that would have a dilutive effect on
earnings per share.
Stock options and unvested restricted stock of approximately 640,000 shares were excluded
in the computation of diluted earnings per share for the year ended December 31, 2009, as
the effect would have been anti-dilutive due to the loss recorded for the year ended
December 31, 2009.
In connection with the Companys outstanding senior exchangeable notes, there could be a
dilutive effect on earnings per share if the price of the Companys common stock exceeds
the initial exchange price of $45.58 per share for a specified period of time. In the
event the Companys common stock exceeds $45.58 per share for a specified period of time,
the first $1.00 the price exceeds $45.58 would cause a dilutive effect of approximately
188,400 shares. As the share price continues to increase, dilution would
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continue to occur but at a declining rate. The impact on the calculation of earnings per
share varies depending on when during the quarter the $45.58 per share price is reached
(see note 8).
(p)
Financial Instruments
The fair value of the Companys financial instruments of cash equivalents, accounts
receivable, equity-method investments and current maturities of long-term debt
approximates their carrying amounts. The fair value of the Companys long-term debt was
approximately $853.2 million and $515.5 million at December 31, 2009 and 2008,
respectively. The fair value of these debt instruments is determined by reference to the
market value of the instrument as quoted in an over-the-counter market.
(q)
Foreign Currency
Results of operations for foreign subsidiaries with functional currencies other than the
U.S. dollar are translated using average exchange rates during the period. Assets and
liabilities of these foreign subsidiaries are translated using the exchange rates in
effect at the balance sheet dates, and the resulting translation adjustments are reported
as accumulated other comprehensive income (loss) in the Companys stockholders equity.
For non-U.S. subsidiaries where the functional currency is the U.S. dollar, financial
statements are remeasured into U.S. dollars using the historical exchange rate for most of
the long-term assets and liabilities and the balance sheet dates exchange rate for most of
the current assets and liabilities. An average exchange rate is used for each period for
revenues and expenses. These transaction gains and losses, as well as any other
transactions in a currency other than the functional currency, are included in general and
administrative expenses in the consolidated statements of operations in the period in
which the currency exchange rates change. The Company recorded approximately $3.5 million
and $4.3 million of foreign currency gains in the years ended December 31, 2009 and 2008,
respectively. For the year ended December 31, 2007, the Company recorded approximately
$0.5 million of such transaction losses.
(r)
Stock-Based Compensation
In accordance with Accounting Standards Codification 718-10 (ASC 718-10),
CompensationStock Compensation, the Company records compensation costs relating to
share based payment transactions within the general and administrative expenses in the
financial statements. The cost is measured at the grant date, based on the calculated
fair value of the award, and is recognized as an expense over the employees requisite
service period (generally the vesting period of the equity award).
(s)
Hedging Activities
During 2008, the Company entered into forward foreign exchange contracts to hedge the
impact of foreign currency fluctuations. The forward foreign exchange contracts generally
have maturities ranging from one to eighteen months. The Company does not enter into
forward foreign exchange contracts for trading purposes. At December 31, 2008, the
Company had foreign currency forward contracts outstanding in order to hedge exposure to
currency fluctuations between the British Pound Sterling and the Euro. These contracts
are not designated as hedges, for hedge accounting treatment, and are marked to fair
market value each period. Based on the exchange rates as of December 31, 2008, the
Company recorded an immaterial gain to adjust these forward contracts to their fair market
value. As of December 31, 2009, we had no outstanding foreign currency forward contracts.
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(t)
Other Comprehensive Income (Loss)
The following table reconciles the change in accumulated other comprehensive income (loss)
for the years ended December 31, 2009 and 2008 (amounts in thousands):
Year Ended December 31,
2009
2008
$
(32,641
)
$
9,078
(3,881
)
6,460
17,526
(48,179
)
13,645
(41,719
)
$
(18,996
)
$
(32,641
)
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2009
2008
2007
$
28,833
$
29,621
$
32,049
$
9,786
$
70,481
$
69,233
$
1,247
$
8,589
$
148,658
(179
)
(32,757
)
(300
)
1,247
8,410
115,601
(4,628
)
$
1,247
$
8,410
$
110,973
$
$
$
12,806
(4,806
)
8,000
$
$
$
8,000
$
5,632
$
297,321
$
12,617
(118,894
)
(2,000
)
(48,571
)
2,900
2,084
40,946
7,483
7,716
173,702
18,100
(18,390
)
$
7,716
$
155,312
$
18,100
$
5,000
$
$
$
484
$
$
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2009
2008
$
105,650
$
83,820
333,350
289,438
1,095,402
1,113,130
26,499
48,820
28,050
25,475
49,483
93,864
12,021
10,934
1,650,455
1,665,481
(591,479
)
(550,540
)
$
1,058,976
$
1,114,941
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December 31,
2009
2008
$
162,870
$
245,416
500,187
645,324
$
663,057
$
890,740
$
81,675
$
407,718
218,003
124,139
$
299,678
$
531,857
Years Ended December 31,
2009
2008
2007
$
245,092
$
315,895
$
224,205
110,101
238,656
175,872
$
134,991
$
77,239
$
48,333
$
(10,024
)
$
58,680
$
35,163
2009
2008
$
300,000
$
300,000
(2,813
)
(3,336
)
400,000
400,000
(38,878
)
(56,631
)
14,166
14,976
177,000
849,475
655,009
810
810
$
848,665
$
654,199
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Net
Principal
Unamortized
Carrying
As of
Amount
Discount
Value
$
400,000
$
56,631
$
343,369
$
400,000
$
33,878
$
366,122
As Originally
Effect of
As
Reported
Change
Adjusted
$
144,534
$
(1,488
)
$
143,046
$
226,421
$
20,403
$
246,824
$
710,830
$
(56,631
)
$
654,199
$
320,309
$
55,127
$
375,436
$
931,787
$
(20,387
)
$
911,400
Year Ended December 31,
2008
2007
$
(16,265
)
$
(15,179
)
6,018
5,617
$
(10,247
)
$
(9,562
)
$
(0.13
)
$
(0.12
)
$
(0.13
)
$
(0.12
)
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during any fiscal quarter (and only during such fiscal quarter), if the last reported
sale price of the Companys common stock is greater than or equal to 135% of the applicable
exchange price of the notes for at least 20 trading days in the period of 30 consecutive
trading days ending on the last trading day of the preceding fiscal quarter;
prior to December 15, 2011, during the five business-day period after any ten
consecutive trading-day period (the measurement period) in which the trading price of
$1,000 principal amount of notes for each trading day in the measurement period was less
than 95% of the product of the last reported sale price of the Companys common stock and
the exchange rate on such trading day;
if the notes have been called for redemption;
upon the occurrence of specified corporate transactions; or
at any time beginning on September 15, 2026, and ending at the close of business on the
second business day immediately preceding the maturity date of December 15, 2026.
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$
810
177,810
810
810
300,810
410,116
$
891,166
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Years Ended December 31,
2009
2008
2007
Actual
Actual
Actual
$
8.95
$
6.40
$
14.34
1.77
%
2.54
%
3.67
%
4
4
5
53.57
%
55.05
%
38.90
%
Weighted
Weighted
Average
Average
Remaining
Aggregate
Number of
Option
Contractual
Intrinsic Value
Options
Price
Term (in years)
(in thousands)
3,970,886
$
12.91
157,035
$
35.84
(867,916
)
$
9.72
(2,333
)
$
9.20
3,257,672
$
14.87
437,530
$
13.86
(426,592
)
$
10.02
(700
)
$
9.31
3,267,910
$
15.37
309,352
$
20.01
(38,717
)
$
9.71
$
3,538,545
$
15.84
5.7
$
33,565
2,895,388
$
15.27
5.0
$
29,090
643,157
$
18.39
9.3
$
4,475
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Options Outstanding
Options Exercisable
Range of
Weighted Average
Weighted
Weighted
Exercise
Remaining
Average
Average
Prices
Shares
Contractual Life
Price
Shares
Price
102,331
2.9 years
$
8.60
102,331
$
8.60
358,780
1.9 years
$
9.39
358,780
$
9.39
1,168,600
4.6 years
$
10.66
1,168,600
$
10.66
437,681
8.8 years
$
12.87
149,230
$
12.86
1,168,555
6.7 years
$
19.55
872,300
$
19.30
294,185
7.5 years
$
35.73
238,538
$
35.74
8,413
8.2 years
$
40.69
5,609
$
40.69
Weighted
Average
Number of
Grant Date
Options
Fair Value
638,212
$
8.67
309,352
$
8.95
(304,407
)
$
9.97
$
643,157
$
8.19
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Weighted
Number of
Average Grant
Shares
Date Fair Value
784,300
$
21.15
319,681
$
20.15
(132,461
)
$
(33.57
)
(14,499
)
$
(20.90
)
957,021
$
19.10
Number of
Weighted
Restricted
Average Grant
Stock Units
Date Fair Value
59,668
$
34.01
33,980
$
20.60
$
93,648
$
29.14
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2009
2008
2007
$
(191,543
)
$
488,666
$
359,821
31,664
53,713
57,492
$
(159,879
)
$
542,379
$
417,313
2009
2008
2007
$
1,555
$
69,065
$
67,211
(256
)
3,699
2,917
16,019
20,047
19,470
17,318
92,811
89,598
(71,874
)
96,770
54,544
(1,831
)
1,805
1,170
(1,169
)
(482
)
443
(74,874
)
98,093
56,157
$
(57,556
)
$
190,904
$
145,755
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2009
2008
2007
$
(55,958
)
$
189,833
$
146,060
(3,712
)
1,865
2,059
2,114
(794
)
(2,364
)
$
(57,556
)
$
190,904
$
145,755
2009
2008
$
8,166
$
3,893
41,154
9,533
22,259
20,211
999
2,478
16,457
20,464
89,035
56,579
(2,394
)
(2,394
)
86,641
54,185
216,411
220,347
16,714
49,451
77,530
60,811
15,540
7,230
326,195
337,839
$
239,554
$
283,654
2009
2008
$
30,501
$
36,830
209,053
246,824
$
239,554
$
283,654
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Subsea and
Drilling
Well
Products and
Consolidated
2009
Enhancement
Services
Marine
Unallocated
Total
$
919,335
$
426,876
$
103,089
$
$
1,449,300
(exclusive of items shown
separately below)
616,116
143,802
64,116
824,034
89,986
105,613
11,515
207,114
149,122
90,318
19,653
259,093
212,527
212,527
2,084
2,084
(148,416
)
87,143
9,889
(51,384
)
(50,906
)
(50,906
)
926
926
571
571
(22,600
)
(22,600
)
(36,486
)
(36,486
)
$
(148,416
)
$
87,143
$
9,889
$
(108,495
)
$
(159,879
)
$
1,377,122
$
759,418
$
299,834
$
80,291
$
2,516,665
$
99,551
$
124,845
$
66,881
$
$
291,277
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Subsea and
Drilling
Oil & Gas
Well
Products and
Eliminations
Consolid.
2008
Enhancement
Services
Marine
Oil & Gas
& Unallocated
Total
$
1,155,221
$
550,939
$
121,104
$
55,072
$
(1,212
)
$
1,881,124
(exclusive of items shown
separately below)
633,127
178,563
74,830
12,986
(1,212
)
898,294
72,169
90,459
10,073
2,799
175,500
163,622
97,624
12,558
8,780
282,584
500
3,332
37,114
40,946
286,803
187,625
23,643
67,621
565,692
(46,684
)
(46,684
)
2,975
2,975
(3,977
)
(3,977
)
24,373
24,373
$
286,803
$
187,625
$
23,643
$
91,994
$
(47,686
)
$
542,379
$
1,343,710
$
762,848
$
239,572
$
121,583
$
22,432
$
2,490,145
$
206,404
$
193,297
$
51,428
$
2,732
$
$
453,861
Subsea and
Drilling
Oil & Gas
Well
Products and
Eliminations
Consolid.
2007
Enhancement
Services
Marine
Oil & Gas
& Unallocated
Total
$
761,015
$
496,290
$
127,898
$
192,700
$
(5,436
)
$
1,572,467
(exclusive of items shown
separately below)
419,818
156,731
60,432
66,580
(5,436
)
698,125
49,786
70,042
8,861
59,152
187,841
118,657
87,442
10,592
11,455
228,146
7,483
7,483
172,754
189,558
48,013
55,513
465,838
(48,436
)
(48,436
)
1,219
1,443
2,662
189
189
(2,940
)
(2,940
)
$
172,754
$
189,558
$
48,013
$
53,792
$
(46,804
)
$
417,313
$
996,946
$
687,944
$
200,623
$
344,667
$
25,115
$
2,255,295
$
145,061
$
166,944
$
19,200
$
75,725
$
3,588
$
410,518
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Revenues
Long-Lived Assets
Years Ended December 31,
December 31,
2009
2008
2007
2009
2008
$
1,126,071
$
1,564,384
$
1,273,705
$
828,662
$
938,453
323,229
316,740
298,762
230,314
176,488
$
1,449,300
$
1,881,124
$
1,572,467
$
1,058,976
$
1,114,941
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Three Months Ended
2009
March 31
June 30
Sept. 30
Dec. 31
$
437,109
$
361,161
$
386,455
$
264,575
222,465
197,268
215,674
188,627
49,868
50,978
52,720
53,548
164,776
112,915
118,061
22,400
56,805
(68,917
)
24,419
(114,630
)
$
0.73
$
(0.88
)
$
0.31
$
(1.46
)
0.72
(0.88
)
0.31
(1.46
)
Three Months Ended
2008
March 31
June 30
Sept. 30
Dec. 31
$
441,391
$
457,655
$
490,282
$
491,796
204,118
222,097
236,610
235,469
41,879
41,954
44,842
46,825
195,394
193,604
208,830
209,502
99,529
71,367
97,294
83,285
$
1.23
$
0.88
$
1.21
$
1.07
1.21
0.86
1.19
1.06
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Level 1
: Unadjusted quoted prices in active markets for identical assets and liabilities.
Level 3
: Unobservable inputs reflecting managements own assumptions about the
inputs used in pricing the asset or liability.
Fair Value Measurements at Reporting Date Using
December 31,
2009
(Level 1)
(Level 2)
(Level 3)
$
12,382
$
4,586
$
7,796
$
$
15,758
$
$
15,758
$
Fair Value Measurements at Reporting Date Using
December 31,
2008
(Level 1)
(Level 2)
(Level 3)
$
7,212
$
$
7,212
$
$
8,254
$
$
8,254
$
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Fair Value Measurements at Reporting Date Using
December 31,
Total
2009
(Level 1)
(Level 2)
(Level 3)
Losses
$
107,591
$
107,591
$
(119,844
)
$
- 0 -
$
- 0 -
$
(92,683
)
$
- 0 -
$
- 0 -
$
(36,486
)
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Crude Oil
Natural Gas
(Mbbls)
(Mmcf)
7,921
35,641
1,206
6,862
519
1,688
(1,817
)
(8,931
)
7,829
35,260
6,493
34,742
$
12,126
76,928
$
89,054
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$
1,043,327
(207,749
)
(251,071
)
(167,305
)
417,202
57,534
$
359,668
$
178,742
(130,130
)
247,708
41,479
(77,239
)
28,761
106,055
15,667
12,545
21,247
(85,167
)
180,926
$
359,668
(20)
Subsequent Events
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(21)
Accounting Pronouncements
Table of Contents
Item 9A.
Controls and Procedures
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Table of Contents
Superior Energy Services, Inc.:
February 26, 2010
Table of Contents
Item 9B.
Other Information
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
Table of Contents
Item 15.
Exhibits, Financial Statement Schedules
(a)
(1) Financial Statements
Consolidated Balance Sheets December 31, 2009 and 2008
Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Changes in Stockholders Equity for the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
Managements Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm Audit of Internal Control over Financial Reporting
Consolidated Statements of Operations for the period from January 1 through October 12, 2009
(predecessor) and for the period from October 13 through December 31, 2009
Consolidated Statements of Cash Flows for the period from January 1 through October 12, 2009
(predecessor) and for the period from October 13 through December 31, 2009
Consolidated Statement of Members Equity/Partners Capital for the period from January 1 through
October 12, 2009
(predecessor) and for the period from October 13 through December 31, 2009
Notes to Consolidated Financial Statements
Supplemental Information (Unaudited)
Statements of Operations for the years ended December 31, 2008 and 2007
Statements of Partners Capital for the years ended December 31, 2008 and 2007
Statement of Cash Flows for the years ended December 31, 2008 and 2007
Notes to Financial Statements
Supplemental Information
Table of Contents
(3)
Exhibits
Exhibit No.
Description
Implementation Agreement, dated December 11, 2009 by and among
Superior Energy Services, Inc., Superior Energy Services (UK) Limited
and Hallin Marine Subsea International Plc. (incorporated herein by
reference to Exhibit 2.1 the Companys Form 8-K filed December 11,
2009).
Rule 2.5 Announcement (incorporated herein by reference to Exhibit 2.2
the Companys Form 8-K filed December 11, 2009).
Certificate of Incorporation of the Company (incorporated herein by
reference to the Companys Quarterly Report on Form 10-QSB for the
quarter ended March 31, 1996 (File No. 000-20310)).
Amended and Restated Bylaws of the Company (as amended through
September 12, 2007) (incorporated herein by reference to Exhibit 3.11
to the Companys Form 8-K filed on September 18, 2007).
Certificate of Amendment to the Companys Certificate of Incorporation
(incorporated herein by reference to the Companys Quarterly Report on
Form 10-Q for the quarter ended June 30, 1999 (File No. 333-22603)).
Specimen Stock Certificate (incorporated herein by reference to
Amendment No. 1 to the Companys Form S-4 on Form SB-2 (Registration
Statement No. 33-94454)).
Indenture, dated May 22, 2006, among the Company, SESI, L.L.C., the
guarantors identified therein and The Bank of New York Trust Company,
N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to
the Companys Form 8-K filed May 23, 2006), as amended by Supplemental
Indenture, dated December 12, 2006, by and among Warrior Energy
Services Corporation, SESI, L.L.C., the other Guarantors (as defined
in the Indenture referred to therein) and The Bank of New York Trust
Company, N.A., as trustee (incorporated herein by reference to Exhibit
4.1 to the Companys 8-K filed December 13, 2006 for the period
beginning December 12, 2006), as further amended by Supplemental
Indenture, dated September 13, 2007 but effective as of August 29,
2007, by and among AOS, SESI, the other Guarantors (as defined in the
Indenture referred to therein) and the Trustee (incorporated herein by
reference to Exhibit 4.1 to the Companys Form 8-K filed on September
18, 2007).
Table of Contents
Exhibit No.
Description
Indenture, dated December 12, 2006, by and among the Company, SESI,
L.L.C., the guarantors named therein and The Bank of New York Trust
Company, N.A., as trustee (incorporated herein by reference to Exhibit
4.1 to the Companys Form 8-K filed December 13, 2006 for the period
beginning December 7, 2006), as amended by Supplemental Indenture,
dated December 12, 2006, by and among Warrior Energy Services
Corporation, SESI, L.L.C., the other Guarantors (as defined in the
Indenture referred to therein) and The Bank of New York Trust Company,
N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to
the Companys Form 8-K filed December 13, 2006 for the period
beginning December 12, 2006), as further amended by Supplemental
Indenture, dated September 13, 2007 but effective as of August 29,
2007, by and among AOS, SESI, the other Guarantors (as defined in the
Indenture referred to therein) and the Trustee (incorporated herein by
reference to Exhibit 4.2 to the Companys Form 8-K filed on September
18, 2007).
Amended and Restated Superior Energy Services, Inc. 1995 Stock
Incentive Plan (incorporated herein by reference to Exhibit A to the
Companys Definitive Proxy Statement dated June 25, 1997 (File No.
000-20310)).
Wreck Removal Contract, dated December 31, 2007, by and among Wild
Well Control, Inc., BP America Production Company, Chevron U.S.A. Inc.
and GOM Shelf LLC (The Company agrees to furnish supplementally a copy
of any omitted exhibits to the SEC upon request) (incorporated herein
by reference to Exhibit 10.1 to the Companys Form 8-K filed on
January 4, 2008).
Employment Agreement between Superior Energy Services, Inc. and
Patrick J. Zuber, dated January 1, 2008 (incorporated herein by
reference to Exhibit 10.1 to the Companys Form 8-K filed on January
7, 2008).
Form of Employment Agreement for Kenneth L. Blanchard and Robert S.
Taylor (incorporated herein by reference to Exhibit 10.1 to the
Companys Form 8-K filed on June 6, 2007).
Superior Energy Services, Inc. 2007 Employee Stock Purchase Plan
(incorporated herein by reference to Exhibit 10.1 to the Companys
Form 8-K filed on May 24, 2007).
Form of Employment Agreement executed by Superior Energy Services,
Inc. and each of Alan P. Bernard, Lynton G. Cook, III, James A.
Holleman and Danny R. Young (incorporated herein by reference to
Exhibit 10.2 to the Companys Form 8-K filed on June 6, 2007).
Employment Agreement between Superior Energy Services, Inc. and
Charles Hardy, dated January 1, 2008 (incorporated herein by reference
to Exhibit 10.2 to the Companys Form 8-K filed on January 7, 2008).
Table of Contents
Exhibit No.
Description
Superior Energy Services, Inc. 1999 Stock Incentive Plan (incorporated
herein by reference to the Companys Annual Report on Form 10-K for
the year ended December 31, 1999 (File No. 333-22603)), as amended by
Second Amendment to Superior Energy Services, Inc. 1999 Stock
Incentive Plan, effective as of December 7, 2004 (incorporated herein
by reference to Exhibit 10.2 to the Companys Form 8-K filed on
December 20, 2004 (File No. 333-22603)).
Employment Agreement between the Company and Terence E. Hall
(incorporated herein by reference to the Companys Annual Report on
Form 10-K for the year ended December 31, 1999 (File No. 333-22603)),
as amended by Letter Agreement dated November 12, 2004 between the
Company and Terence E. Hall (incorporated herein by reference to
Exhibit 10.1 to the Companys Form 8-K filed on November 15, 2004
(File No. 333-22603)), as amended by Amendment No. 2 to Amended and
Restated Employment Agreement dated as of December 29, 2008, between
the Company and Terence E. Hall (incorporated herein by reference to
Item 10.1 to the Companys Form 8-K filed January 2, 2009).
Amended and Restated Superior Energy Services, Inc. 2002 Stock
Incentive Plan (incorporated herein by reference to the Companys
Annual Report on Form 10-K for the year ended December 31, 2003 (File
No. 333-22603)), as amended by First Amendment to Superior Energy
Services, Inc. 2002 Stock Incentive Plan, effective as of December 7,
2004 (incorporated herein by reference to Exhibit 10.1 to the
Companys Form 8-K filed on December 20, 2004 (File No. 333-22603)).
Superior Energy Services, Inc. Nonqualified Deferred Compensation Plan.
Superior Energy Services, Inc. 2005 Stock Incentive Plan (incorporated
herein by reference to Appendix A to the Companys Definitive Proxy
Statement dated April 18, 2005).
Amended and Restated Superior Energy Services, Inc. 2004 Directors
Restricted Stock Units Plan (incorporated herein by reference to
Appendix B to the Companys Definitive Proxy Statement dated April 20,
2006).
Confirmation of OTC Exchangeable Note Hedge, dated December 7, 2006,
by and between SESI, L.L.C. and Bear, Stearns International, Limited
(incorporated herein by reference to Exhibit 10.3 to the Companys
Form 8-K filed December 13, 2006 for the period beginning December 7,
2006).
Confirmation of OTC Exchangeable Note Hedge, dated December 7, 2006,
by and between SESI, L.L.C. and Lehman Brothers OTC Derivatives Inc.
(incorporated herein by reference to Exhibit 10.4 to the Companys
Form 8-K filed December 13, 2006 for the period beginning December 7,
2006).
Confirmation of OTC Warrant Confirmation, dated December 7, 2006, by
and between the Company and Bear, Stearns International, Limited
(incorporated herein by reference to Exhibit 10.5 to the Companys
Form 8-K filed December 13, 2006 for the period beginning December 7,
2006).
Table of Contents
Exhibit No.
Description
Confirmation of OTC Warrant Confirmation, dated December 7, 2006, by
and between the Company and Lehman Brothers OTC Derivatives Inc.
(incorporated herein by reference to Exhibit 10.6 to the Companys
Form 8-K filed December 13, 2006 for the period beginning December 7,
2006).
Purchase, Contribution and Redemption Agreement, dated February 25,
2008, by and among Dynamic Offshore Resources, LLC, Moreno Group LLC,
SESI, LLC, and SPN Resources, LLC (incorporated herein by reference to
Exhibit 10.1 to the Companys Form 8-K filed February 29, 2008).
Employment Agreement, dated March 1, 2008, by and between Superior
Energy Services, Inc. and William B. Masters (incorporated herein by
reference to Exhibit 10.1 to the Companys Form 8-K filed March 6,
2008).
Letter agreement between Superior Energy Services, Inc. and Patrick J.
Zuber, dated December 22, 2008 (incorporated herein by reference to
the Companys Annual Report on Form 10-K for the year ended December
31, 2008).
Superior Energy Services, Inc. Supplemental Executive Retirement Plan.
Superior Energy Services, Inc. 2009 Stock Incentive Plan (incorporated
herein by reference to Exhibit 10.1 to the Form 8-K filed on May 27,
2009).
Employment Agreement between Superior Energy Services, Inc. and
Patrick J. Campbell, dated March 30, 2009 (incorporated herein by
reference to Exhibit 10.1 to the Companys Form 8-K filed April 2,
2009).
Second Amended and Restated Credit Agreement dated May 29, 2009 among
Superior Energy Services, Inc., SESI, L.L.C., JPMorgan Chase Bank,
N.A. and the lenders party thereto (incorporated herein by reference
to Exhibit 10.1 to the Companys Form 8-K filed June 1, 2009).
Form of Stock Option Agreement under the Superior Energy Services,
Inc. 2005 Stock Incentive Plan and the 2009 Stock Incentive Plan
(incorporated herein by reference to Exhibit 10.1 to the Companys
Form 8-K filed December 16, 2009).
Form of Restricted Stock Agreement under the Superior Energy Services,
Inc. 2005 Stock Incentive Plan and the 2009 Stock Incentive Plan
(incorporated herein by reference to Exhibit 10.1 to the Companys
Form 8-K filed December 16, 2009).
Form of Performance Share Unit Award Agreement under the Superior
Energy Services, Inc. 2005 Stock Incentive Plan and the 2009 Stock
Incentive Plan (incorporated herein by reference to Exhibit 10.1 to
the Companys Form 8-K filed December 16, 2009).
Code of business ethics and conduct (incorporated herein by reference
to the Companys Annual Report on Form 10-K for the year ended
December 31, 2003 (File No. 333-22603)).
Subsidiaries of the Company.
Consent of KPMG LLP, independent registered public accounting firm.
Table of Contents
Exhibit No.
Description
Consent of Hein & Associates LLP, independent registered public
accounting firm.
Consent of DeGoyler and MacNaughton
Officers certification pursuant to Rules 13a-14(a) and 15d-14(a)
under the Securities Exchange Act of 1934, as amended.
Officers certification pursuant to Rules 13a-14(a) and 15d-14(a)
under the Securities Exchange Act of 1934, as amended.
Officers certification pursuant to Section 1350 of Title 18 of the
U.S. Code.
Officers certification pursuant to Section 1350 of Title 18 of the
U.S. Code.
*
Filed herein
^
Management contract or compensatory plan or arrangement.
Table of Contents
Date: February 26, 2010
SUPERIOR ENERGY SERVICES, INC.
By:
/s/ Terence E. Hall
Terence E. Hall
Chairman of the Board and
Chief Executive Officer
Signature
Title
Date
Chairman of the Board and Chief
Executive Officer
(Principal Executive Officer)
February 26, 2010
Executive Vice President, Treasurer and Chief
Financial Officer
(Principal Financial and Accounting Officer)
February 26, 2010
Director
February 26, 2010
Director
February 26, 2010
Director
February 26, 2010
Director
February 26, 2010
Director
February 26, 2010
Table of Contents
Schedule II Valuation and Qualifying Accounts
Years Ended December 31, 2009, 2008 and 2007
(in thousands)
Additions
Balance at the
Charged to
Balance
beginning of
costs and
Balances from
at the end
Description
the year
expenses
acquisitions
Deductions
of the year
$
18,013
$
10,866
$
$
5,200
$
23,679
$
16,742
$
6,471
$
$
5,200
$
18,013
$
17,419
$
3,833
$
404
$
4,914
$
16,742
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Supplemental Information (Unaudited)
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Table of Contents
Page
1
2
3
4
5
6
21
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DBH, LLC
Hein & Associates LLP
Houston, Texas
February 24, 2010
Table of Contents
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2009
$
43,928
13,556
33,300
1,763
7,931
100,478
311,465
(8,510
)
302,955
6,945
$
410,378
$
6,115
2,848
19,716
19,113
47,792
105,000
56,676
1,145
5,492
216,105
194,273
$
410,378
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CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
DBH, LLC
Predecessor
October 13
January 1
through
through
December 31,
October 12,
2009
2009
$
27,439
$
89,599
7,923
33,640
2,159
330
8,510
89,046
3,983
17,523
5,232
18,537
27,807
159,076
(368
)
(69,477
)
(2,197
)
(22,411
)
667
24,132
160,877
$
158,979
$
(67,756
)
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CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
DBH, LLC
Predecessor
October 13 through
January 1 through
December 31,
October 12,
2009
2009
$
158,979
$
(67,756
)
16
1,934
950
4,496
8,510
89,045
(619
)
15,471
(43
)
(22
)
1,391
(160,877
)
7,975
(27,506
)
(4,218
)
8,819
10,673
25,872
(3,703
)
(65,197
)
40,524
42
300
12,615
(1,032
)
49,478
(65,929
)
(46,223
)
(300
)
32,160
(2,160
)
(16,223
)
(300
)
43,928
(40,357
)
80,881
$
43,928
$
40,524
$
2,191
$
15,355
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CONSOLIDATED STATEMENT OF MEMBERS EQUITY/PARTNERS CAPITAL
(In thousands)
Predecessor
$
144,904
(67,756
)
1,487
(11,618
)
(10,131
)
(77,887
)
$
67,017
DBH, LLC
$
5,294
32,160
(2,160
)
158,979
$
194,273
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Notes to Consolidated Financial Statements
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Table of Contents
Table of Contents
Table of Contents
Table of Contents
Table of Contents
$
12,410
1,146
$
13,556
$
5,706
1,523
593
109
$
7,931
$
6,746
199
$
6,945
$
5,142
350
$
5,492
DBH, LLC
Predecessor
October 13
January 1
through
through
December 31,
October 12,
2009
2009
$
2,424
$
8,652
1,898
2,663
950
4,496
(40
)
2,726
$
5,232
$
18,537
the Company issued a member interest with a fair value of $5.3 million to acquire a loan
receivable from Bandon with a face value of $119.5 million; and
in a nonmonetary exchange with the owners of the Predecessor, the Company exchanged the
loan receivable for a 100% ownership interest in Bandon.
Table of Contents
$
117,038
978
15,829
Table of Contents
$
221,122
59,000
30,000
1,343
311,465
(8,510
)
$
302,955
DBH, LLC
Predecessor
October 13 through
January 1 through
December 31,
October 12,
2009
2009
$
$
90,084
82,878
(8,039
)
(641
)
950
4,496
1,708
$
75,789
$
95,647
$
105,000
$
105,000
$
Table of Contents
Table of Contents
Table of Contents
Avg. Price
Barrels
Instrument Type
Index
$/Bbl
2010
2011
2012
Fair Value
CL-NYM
$
78.00
240,000
$
(885
)
CL-NYM
78.00
106,000
(820
)
240,000
106,000
$
(1,705
)
Avg. Price
MMBtu
Instrument Type
Index
$/MMBtu
2010
2011
2012
Fair Value
NG-NYM
$
6.31
4,545,000
$
2,648
NG-NYM
6.31
2,205,000
(89
)
NG-NYM
6.31
1,340,000
(236
)
4,545,000
2,205,000
1,340,000
$
2,323
Asset Derivatives
Liability Derivatives
Balance
Balance
Derivatives not designated as hedging
Sheet
Fair
Sheet
Fair
instruments under ASC 815
Location
Value
Location
Value
Current assets
$
1,763
Long-term liabilities
$
1,145
DBH, LLC
Predecessor
October 13 through
January 1 through
Location of Gain (Loss) Reclassified
December 31,
October 12,
from AOCI into Income
2009
2009
$
$
11,618
(1,487
)
$
$
10,131
Table of Contents
Level 1, defined as observable inputs such as quoted prices in active markets;
Level 2, defined as inputs other than quoted prices in active markets that are either
directly or indirectly observable; and
Level 3, defined as unobservable inputs in which little or no market data exists,
therefore requiring an entity to develop its own assumptions.
Total
Level 1
Level 2
Level 3
$
1,763
$
$
1,763
$
$
1,145
$
$
1,145
$
DBH, LLC
Predecessor
October 13
January 1
through
through
December 31,
October 12,
2009
2009
$
$
(1,940
)
451
1,489
$
$
Table of Contents
$
1,800
128
156
$
2,084
Table of Contents
Table of Contents
(Unaudited)
Crude oil
Natural gas
(MBbl)
(MMcf)
3,920
76,803
39
540
583
(965
)
(835
)
(12,479
)
3,707
63,899
3,385
66,752
3,297
57,295
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$
$
2,489
32,852
$
35,341
Future costs and selling prices will probably differ from those required to be used
in these calculations.
Due to future market conditions and governmental regulations, actual rates of
production achieved in future years may vary significantly from the rate of production
assumed in the calculations.
Selection of a 10% discount rate is required by ASC 932 and may not be reasonable as
a measure of the relative risk inherent in realizing future net oil and gas revenues.
$
447,505
(127,437
)
(141,077
)
178,991
(31,181
)
$
147,810
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$
198,321
(59,297
)
(81,632
)
21,275
2,375
7,760
32,852
9,184
16,972
(50,511
)
$
147,810
Table of Contents
Supplemental Information
Table of Contents
Balance Sheets
Unaudited
December 31, 2008 and 2007
(in thousands)
Table of Contents
Statements of Operations
Unaudited
Years ended December 31, 2008 and 2007
(in thousands)
2008
2007
$
79,367
$
87,767
106,476
136,230
185,843
223,997
47,789
37,833
9,517
14,246
1,445
891
2,802
4,873
76,924
104,250
34,878
7,881
5,035
5,816
2,491
(101
)
(1,930
)
12,296
15,098
193,177
188,857
(31,158
)
(41,246
)
2,032
4,140
(708
)
17,430
(5,968
)
(11,696
)
(43,782
)
$
(19,030
)
$
(8,642
)
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Statements of Partners Capital
Unaudited
Years ended December 31, 2008 and 2007
(in thousands)
Superior
Energy
Beryl
Services,
Resources
Inc
LP
Total
$
69,083
$
103,625
$
172,708
(3,457
)
(5,185
)
(8,642
)
(9,683
)
(14,525
)
(24,208
)
(13,140
)
(19,710
)
(32,850
)
55,943
83,915
139,858
(7,612
)
(11,418
)
(19,030
)
9,631
14,445
24,076
2,019
3,027
5,046
$
57,962
$
86,942
$
144,904
Table of Contents
Statements of Cash Flows
Unaudited
Years ended December 31, 2008 and 2007
(in thousands)
2008
2007
$
(19,030
)
$
(8,642
)
76,924
104,250
34,878
7,881
5,035
5,816
(15,663
)
23,729
3,727
1,981
(1,930
)
708
2,491
(101
)
19,295
(6,642
)
(6,138
)
10,378
(1,064
)
(1,345
)
(986
)
(28
)
(634
)
(567
)
(1,656
)
97,179
135,488
(1,653
)
(389
)
(62,596
)
(44,091
)
(167
)
(2,141
)
(64,416
)
(46,621
)
(24,246
)
(111,940
)
(24,246
)
(111,940
)
8,517
(23,073
)
72,364
95,437
$
80,881
$
72,364
$
25,538
$
39,295
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
(1)
Organization and Summary of Significant Accounting Policies
(a)
Organization and Nature of Business
Beryl Oil and Gas LP (the Partnership), which changed its name from Coldren Resources LP
in May 2007, is a Delaware limited partnership that was organized in May 2006 for the
purpose of acquiring offshore oil and gas properties. The Partnership is a joint venture
between Beryl Resources LP (BR), formerly named Coldren Oil and Gas Company LP, and
Superior Energy Services, Inc. (SESI). BR owns 60% of the Partnership and acts as the
managing partner, while SESI owns 40%. The Partnership has no employees and all business
activity was managed by BR or SESI personnel during 2008 and 2007.
(b)
Basis of Presentation
The accompanying financial statements have been prepared on an accrual basis of
accounting, in accordance with accounting principles generally accepted in the United
States of America.
(c)
Cash Equivalents
The Partnership considers all highly liquid investments with an original maturity of
three months or less when purchased to be cash equivalents. Cash equivalents are stated
at cost, which approximates market value.
(d)
Accounts Receivable and Allowances
Trade accounts receivables are recorded at the invoiced amount and do not bear interest.
The Partnership determines the allowances based on historical write-off experience and
specific identification. As of December 31, 2008, the Partnership had $0.5 million of
allowances for doubtful accounts. There were no such allowances for doubtful accounts as
of December 31, 2007.
(e)
Property and Equipment
Proved Oil and Properties
The Partnership accounts for oil and gas properties under the successful efforts method.
Under this method, all leasehold and development cost of proved properties are
capitalized and amortized on a unit-of-production basis over the remaining life of proved
reserves and proved developed reserves, respectively.
The Partnership evaluates the impairment of its proved oil and gas properties on a
depletable unit basis whenever events or changes in circumstances indicate an assets
carrying amount may not be recoverable. The carrying amount of proved oil and gas
properties, is reduced to fair value when the expected undiscounted future cash flows are
less than the assets net book value. Cash flows are determined based upon reserves using
prices, costs, and discount factors consistent with those used for internal decision
making. Costs of retired, sold, or abandoned properties that constitute a part of an
amortization base are charged or credited, net of proceeds, to accumulated depreciation,
depletion,
and amortization unless doing so significantly affects the unit-of-production
amortization rate, in which case a gain or loss is recognized currently. Gains or losses
from the disposal of other
6
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
properties are recognized currently. Expenditures for maintenance and repairs necessary
to maintain properties in operating condition are expensed as incurred as part of lease
operating expenses. Estimated dismantlement and abandonment costs for oil and gas
properties are capitalized at their estimated net present value and amortized on a
unit-of-production basis over the remaining life of the related proved developed
reserves.
Unproved Oil and Gas Properties
Unproved properties consist of costs incurred to acquire unproved leasehold as well as
costs to acquire unproved resources. Unproved leasehold costs are capitalized and
amortized on a composite basis if individually insignificant, based on past success,
experience, and average lease-term lives. Individually significant leases are
reclassified to proved properties if successful and expensed on a lease-by-lease basis if
unsuccessful or the lease term has expired. Unamortized leasehold costs related to
successful exploratory drilling are reclassified to proved properties and depleted on a
unit-of-production basis. The carrying value of the Partnerships unproved resources,
acquired in connection with business acquisitions, was determined using the market-based
weighted average cost of capital rate, subjected to additional project-specific risk
factors. Because these reserves do not meet the definition of proved reserves, the
related costs are not classified as proved properties. As the unproved resources are
developed and proved, the associated costs are reclassified to proved properties and
depleted on a unit-of-production basis. The Partnership assesses unproved resources for
impairment annually on the basis of the experience of the Partnership in similar
situations and other information about such factors as the primary lease terms of those
properties, the average holding period of unproved properties, and the relative
proportion of such properties on which proved reserves have been found in the past.
Impairment
Based on the analysis described above, the Partnership recorded an impairment of oil and
gas properties of approximately $34.9 million for the year ended December 31, 2008, which
is included in impairment and dry hole expense on the statement of operations. The
Partnership recorded a noncash impairment of approximately $7.9 million of oil and gas
properties for the year ended December 31, 2007.
Exploration Costs
Geological and geophysical costs, delay rentals, amortization of unproved leasehold
costs, and costs to drill exploratory wells that do not find proved reserves are expensed
as oil and gas exploration costs. The costs of any exploratory wells are carried as an
asset if the well finds a sufficient quantity of reserves to justify its capitalization
as a producing well and as long as the Partnership is making
sufficient progress towards assessing the reserves and the economic and operating
viability of the project.
Other Property and Equipment
Other property and equipment, consisting primarily of office furniture, equipment,
leasehold improvements, computers, and computer software, are stated at cost.
Depreciation on property and
7
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
equipment is calculated on the straight-line method over the estimated useful lives of
the assets, which range from three to seven years.
(f)
Asset Retirement Obligations
The Partnership accounts for its asset retirement obligations in accordance with
Statement of Financial Accounting Standards (SFAS) No. 143,
Accounting for Asset
Retirement Obligations
. SFAS No. 143 requires the Partnership to record the fair value of
obligations associated with the retirement of tangible long-lived assets in the period in
which it is incurred. The liability is capitalized as part of the related long-lived
assets carrying amount. Over time, accretion of the liability is recognized as an
operating expense and the capitalized cost is depleted over the expected useful life of
the related asset. The Partnerships asset retirement obligations relate primarily to the
plugging, dismantlement, removal, site reclamation, and similar activities of its oil and
gas properties.
(g)
Financial Instruments
The fair value of the Partnerships financial instruments of cash, accounts receivable,
and current maturities of long-term debt approximates their carrying amount. The carrying
value of the Partnerships debt is approximately $298.8 million and $323.1 million at
December 31, 2008 and 2007, respectively. The fair value of the Partnerships cash and
cash equivalents is approximately $80.9 million and $72.4 million at December 31, 2008
and 2007, respectively.
(h)
Revenue Recognition
The Partnership records revenues from the sale of its oil and gas production when the
product is delivered at a determinable price, title has transferred, and collectibility
is reasonably assured. When the Partnership has an interest with other producers in
properties from which natural gas is produced, the Partnership uses the entitlement
method for recording gas sales revenue. Under this method of accounting, revenue is
recorded based on the Partnerships net revenue interest in field production. Deliveries
of gas in excess of the Partnerships revenue interest are recorded as liabilities and
underdeliveries are recorded as receivables. The Partnership also had gas imbalance
receivables of $11.1 million and producer gas payables of $8.6 million at December 31,
2008. The Partnership had gas imbalance receivables of $7.1 million and producer gas
payables of $5.6 million at December 31, 2007.
(i)
Derivative Instruments and Hedging Activities
The Partnership accounts for derivative instruments and hedging activities in accordance
with SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities
, as
amended (SFAS No. 133). SFAS No. 133 established accounting and reporting standards
requiring every derivative instrument (including certain derivative instruments embedded
in other contracts) to be recorded on the balance sheet as either an asset or liability
measured at fair value. SFAS No. 133 requires that changes in the derivatives fair value
be recognized currently in earnings unless specific hedge accounting criteria are met.
Under cash flow hedge accounting, gains and losses are reflected in partners capital as
accumulated other comprehensive income or loss (AOCI) until the forecasted
8
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
transaction occurs. The derivatives gains or losses are then offset against related
results on the hedged transaction on the statement of operations. SFAS No. 133 also
requires that a company formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. Only derivative instruments that are expected
to be highly effective in offsetting anticipated gains or losses on the hedged cash flows
and that are subsequently documented to have been highly effective can qualify for hedge
accounting. Effectiveness must be assessed both at inception of the hedge and on an
ongoing basis. Any ineffectiveness in hedging instruments whereby gains or losses do not
exactly offset anticipated gains or losses of hedged cash flows is measured and
recognized in earnings in the period in which it occurs. The Partnership assesses hedge
effectiveness on an ongoing basis based on total changes in the derivatives fair value
and using regression analysis. A hedge is considered effective if certain statistical
tests are met. For derivatives not qualifying for hedge accounting, the changes in fair
value are recorded as other income (expense) on the consolidated statements of
operations.
Through October 31, 2008, the Partnership elected to designate the majority of its crude
oil and natural gas derivative instruments as cash flow hedges. On November 1, 2008, the
Partnership discontinued cash flow hedge accounting on all existing commodity derivative
instruments. The Partnership voluntarily made this change to provide greater flexibility
in its use of derivative instruments. From November 1, 2008 forward, the Partnership
recognized all realized and unrealized gains and losses on such instruments in earnings
in the period in which they occur. Net derivative losses that were deferred in AOCI as of
October 31, 2008, will be reclassified to earnings in future periods as the original
hedged transactions affect earnings. During 2008, the Partnership reclassified $1.9
million of derivative gains from other comprehensive income to net loss as it was
probable that the original forecasted transaction would not occur by the end of the
original period or an additional two-month time period. The discontinuance of cash flow
hedge accounting for commodity derivative instruments did not affect the Partnerships
net assets or cash flows at December 31, 2008 and does not require adjustments to
previously reported financial statements.
(j)
Income Taxes
The Partnership does not pay income taxes as profits or losses are reported directly to
the taxing authorities by the individual partners. Accordingly, no provision for income
taxes has been included in the accompanying financial statements.
(k)
Deferred Financing Costs
Costs incurred to obtain debt financing are deferred and are amortized as additional
interest expense over the maturity period of the related debt.
(l)
Allocation of Income and Distributions to Partners
The partnership agreement allows for revenues and expenditures to be allocated between
the general partner and limited partner in accordance with their respective sharing
ratios.
9
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
(m)
Use of Estimates
The preparation of the financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and the
reported amounts of revenues and expenses during the reporting period. The Partnerships
most significant financial estimates are based on remaining proved oil and natural gas
reserve volumes. Estimates of remaining proved reserve volumes are a key component in
determining the Partnerships depletion rate for oil and gas properties. Estimation of
the values of the Partnerships remaining proved reserves is a key component in
determining the need for impairment of the oil and natural gas asset base. These
estimates require assumptions regarding future commodity prices and future costs and
expenses, as well as future production rates. Actual results could differ from these
estimates.
(n)
Recently Issued Accounting Standards
In February 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial Liabilities Including an
amendment of FASB Statement No. 115
. SFAS No. 159 gives the Partnership the irrevocable
option to carry most financial assets and liabilities at fair value that are not
currently required to be measured at fair value. If the fair value option is elected,
changes in fair value would be recorded in earnings at each subsequent reporting date.
SFAS No. 159 is effective for the Partnerships 2008 fiscal year. The adoption of this
statement did not have a material impact on the Partnerships financial condition,
results of operations, and cash flows.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements
. SFAS No. 157
defines fair value, establishes a framework for the measurement of fair value, and
enhances disclosures about fair value measurements. The statement does not require any
new fair value measures. The statement is effective for fair value measures already
required or permitted by other standards for fiscal years beginning after November 15,
2007. The Partnership was required to adopt SFAS No. 157 beginning on January 1, 2008.
SFAS No. 157 is required to be applied prospectively, except for certain financial
instruments. Any transition adjustment will be recognized as an
adjustment to opening retained earnings in the year of adoption. In November 2007, the
FASB proposed a one-year deferral of SFAS No. 157s fair value measurement requirements
for nonfinancial assets and liabilities that are not required or permitted to be measured
at fair value on a recurring basis. The Partnership adopted SFAS No. 157 and the impact
on its results of operations and financial position is approximately $0.4 million during
2008.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations,
and SFAS No.
160,
Noncontrolling Interests in Consolidated Financial Statements an amendment to ARB
No. 51
. SFAS Nos. 141(R) and 160 require most identifiable assets, liabilities,
noncontrolling interests, and goodwill acquired in a business combination to be recorded
at full fair value and require noncontrolling interests (previously referred to as
minority interests) to be reported as a component of equity, which changes the accounting
for transactions with noncontrolling interest holders. Both statements are effective for
periods beginning on or after December 15, 2008, and earlier adoption is prohibited. SFAS
No. 141(R) will be applied to business combinations occurring after the effective
10
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
date. SFAS No. 160 will be applied prospectively to all noncontrolling interests,
including any that arose before the effective date. The Partnership is currently
evaluating the impact of adopting SFAS Nos. 141(R) and 160 on its results of operations
and financial position.
(2)
Significant Concentrations
For the years ended December 31, 2008 and 2007, the Partnerships oil and gas revenue
(excluding the effects of hedging activities) was attributable to the following significant
customers, as a percentage of total revenues:
December 31,
2008
2007
%
9
%
19
17
24
14
20
14
24
11
87
%
65
%
(3)
Related-Party Transactions
The Partnership has an operating services agreement that covers services provided by BR and
SESI. BR and SESI provide operational and accounting functions under the operating services
agreement that provides for reimbursement of all direct and indirect costs incurred as part of
the agreement. These management fees were paid to SESI and recorded by the Partnership as
general and administrative expenses totaling $0.5 million and $4.1 million for the years ended
December 31, 2008 and 2007,
respectively. BR charged the Partnership approximately $0.4 million and $5.2 million and in
general and administrative expenses for the years ended December 31, 2008 and 2007,
respectively. During 2008 and 2007, the Partnership paid approximately $3.6 million and $7.8
million in services to SESI, respectively.
Accounts payable to affiliates is as follows (in thousands):
December 31,
2008
2007
$
36
$
1,268
1,138
817
678
753
$
1,852
$
2,838
11
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
(4)
Acquisitions and Divestitures
During 2008, the Partnership purchased unproved leases for $1.7 million. The Partnership also
purchased additional interest in one of its fields. It paid no cash, but received
approximately $1.0 million for the Asset Retirement Obligation (ARO) liability that was
assumed.
During 2007, the Partnership sold its interests in one field for the assumption of the related
asset retirement obligations, recording a gain of $1.9 million. The Partnership also purchased
unproved leases for $0.4 million during 2007.
(5)
Property and Equipment
A summary of property and equipment is as follows (in thousands):
December 31,
2008
2007
$
665,459
$
574,565
13,811
40,941
2,794
2,627
682,064
618,133
(239,189
)
(162,265
)
$
442,875
$
455,868
The Partnership recognized $34.9 million and $7.9 million of impairment and dry hole expense
during 2008 and 2007, respectively. The impairments comprised proved properties, probable
reserves, and unproved leases during 2008 and proved properties and unproved leases during
2007.
Unproved properties comprise a lease bonus that is being amortized over the term of the lease
and probable reserve values, which are reviewed annually for impairment. During 2008 and 2007,
the Partnership recorded amortization of its unproved properties of $2.2 million and $2.8
million, respectively, which is included in depreciation, depletion, and amortization expense.
Substantially, all of the Partnerships oil and natural gas properties serve as collateral for
the Partnerships long-term debt.
12
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
(6)
Asset Retirement Obligations
The following table summarizes the activity for the Partnerships asset retirement obligations
for the years ended December 31, 2008 and 2007 (in thousands):
2008
2007
$
79,614
$
89,525
2,940
(165
)
(2,033
)
5,035
5,816
2,660
(13,694
)
90,084
79,614
14,785
2,811
$
75,299
$
76,803
(7)
Long-Term Debt
The carrying amount of the Partnerships long-term borrowings that were outstanding subject to
interest rate risk consists of the following (in thousands) at:
December 31,
2008
2007
$
179,358
$
203,602
119,457
119,457
298,815
323,059
26,223
24,246
272,592
298,813
(1,385
)
(1,905
)
$
271,207
$
296,908
On July 14, 2006, the Partnership entered into a First Lien Agreement and Second Lien
Agreement with Credit Suisse Securities, LLC and Banc of America Securities, LLC to fund its
acquisition of oil and gas properties from Noble Energy, Inc. The First Lien Agreement of
$311.0 million bears interest at LIBOR plus 4% margin and the Second Lien Agreement of $124
million bears interest at LIBOR plus 6% margin.
13
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
The First Lien Agreement matures on July 14,
2011 and the Second Lien Agreement matures on January 13, 2012. Both agreements require
interest payments in March, June, September, and December. The lien agreements contain
customary events of default and requires that the Partnership satisfy various financial
covenants, which require the Partnership to: (i) maintain a minimum asset coverage ratio, as
defined in the lien agreements, (ii) maintain a minimum earnings before interest, taxes,
depreciation, abandonment, and exploration and other noncash charges (EBITDAX) to interest
ratio, as defined in the lien agreements, and
(iii) maintain a leverage ratio, as defined in the lien agreements. The lien agreements also
limit the Partnerships capital expenditures, its ability to pay dividends or make other
distributions, make acquisitions, make changes to the Partnerships capital structure, create
liens, and incur additional indebtedness. The agreements also require the Partnership to enter
into interest rate protection agreements and commodity price hedging programs for its debt and
sales of natural gas and oil.
The First and Second Lien Agreements with Credit Suisse provide for a Mandatory Prepayment, as
defined, which is equal to the Required Percentage of Excess Cash Flow for the period provided
that a Liquidity Reserve of $25 million is maintained at all times. Excess Cash Flow is
defined as EBITDAX less working capital changes, capital expenditures, and exploration
expenses. As of December 31, 2008 and 2007, the Mandatory Prepayment is $0 and $24.2 million,
respectively. The First and Second Lien Agreements with Credit Suisse also allows for an
Optional Prepayment, equal to no less than $5.0 million and which must be in multiples of $1.0
million. The Optional Prepayment on the First Lien was subject to a prepayment premium of 1%
of the Optional Prepayment amount if prepaid within the first year of the loan. The Optional
Prepayment on the Second Lien is subject to a prepayment premium of 3%, 2%, and 1%, of the
Optional Prepayment amount if prepaid within the first year, second year, and third year,
respectively, of the loan. During 2008 and 2007, the Partnership repaid $24.2 million and
$111.9 million, respectively, of its outstanding long-term debt and incurred a prepayment
penalty of $0 and $0.5 million, which is recorded in interest expense.
The Partnership had a revolving letter of credit facility of $50.0 million during 2007. During
2007, the Partnership terminated its letter of credit facility, which had no outstanding
balances and recorded a loss on extinguishment of debt related to unamortized fees of $0.7
million. During 2007, the Partnership recorded $1.7 million in administrative fees related to
the letter of credit facility, which is recorded as a component of general and administrative
expenses on the statement of operations.
As of December 31, 2008, the Partnership violated the covenant to maintain a leverage ratio of
1.25 to 1.00, or greater, on the First Lien and 1.50 to 1.00, or greater, on the Second Lien.
As a result, the Partnership was in default on both the First and Second Lien Agreements. At
the point of default, the full amount of both the First and the Second Lien became callable;
however, the amounts due were not reclassified to current maturities of long-term debt because
the Partnership was recapitalized and the debt was restructured to long-term on October 13,
2009 as discussed in note 13. The restructuring included replacing the First Lien Agreement
with an amended agreement and the forgiveness of $27.9 million of amounts due. The Second Lien
Term Loan was exchanged for an equity interest in the Partnership. The current maturities of
long-term debt of $26.2 million as of December 31, 2008, represent a mandatory prepayment
under the restructured Lien Agreements due and paid on October 13, 2009.
14
(Continued)
Table of Contents
(8)
Interest Rate Hedging Agreements
During 2006, the Partnership entered into an interest rate swap on notional amounts of the
floating rate term loans, which expired during 2007. During 2006, the Partnership also entered
into a collar agreement with a notional cap amount of $50 million and a floor of $25 million
of the floating rate term loans, which expired in 2008. Finally during 2006, the Partnership
entered into a collar agreement with a notional cap amount of $150 million and a floor of $75
million of floating rate term loans as follows:
Interest rate derivative positions
Instrument
Strike
Notional
Contract team
type
interest rate
amounts
Loan rate
09/06 09/09
Collars
5.4190%
$150 million and
$75 million
LIBOR+ %
On October 31, 2008, the Partnership dedesignated its interest rate hedges as cash flow
hedges. For the period from November 1, 2008 to December 31, 2008, the Partnership accounted
for the change in valuation of the hedges as mark-to-market resulting in an unrealized loss of
$0.1 million, recorded in other income.
At December 31, 2008, the fair value of the interest rate derivatives had a short-term
liability of $1.9 million, long-term liability of $0, and an unrealized loss of $1.9 million,
which is reflected in accumulated other comprehensive income. At December 31, 2007, the fair
value of the interest rate derivatives had a short-term liability of $0.2 million, long-term
liability of $2.0 million, and an unrealized loss of $2.2 million, which is reflected in other
comprehensive loss. These values were based on quoted market prices for contracts with similar
terms and maturity dates. During 2008 and 2007, the Partnership (paid) received interest rate
settlements from its counterparties of ($1.9 million) and $0.1 million respectively, which are
included in interest expense.
15
(Continued)
Table of Contents
(9)
Oil and Gas Commodity Hedging Agreements
The Partnership had the following oil and gas commodity hedging contracts as of December 31,
2008:
Commodity derivatives
Crude oil swaps
Coverage
Instrument
Strike
Reference or
period
type
price (per Bbl)
floating price
Total (Bbls)
1
Swap
$78.32
NYMEX WTI
321,358
Swap
81.47
NYMEX WTI
180,362
Natural gas swaps
Coverage
Instrument
Strike
Reference or
period
type
price (per MMBtu)
floating price
Total (MMBtu)
2
2009
Swap
$8.46
NYMEX
4,390,004
Swap
8.43
NYMEX
2,681,144
Natural gas floors
3
Coverage
Instrument
Strike
Reference or
period
type
price (per MMBtu)
floating price
Total (MMBtu)
2
Floor
$8.25
NYMEX
7,300,000
(1)
Bbls equals Barrel of oil
(2)
MMBtu equals Million British Thermal Units
(3)
The Partnership paid $2.5 million to purchase these puts in 2008
On October 31, 2008, the Partnership dedesignated its commodity hedges as cash flow
hedges. For the period from November 1, 2008 to December 31, 2008, the Partnership accounted
for the change in valuation of the hedges as mark-to-market resulting in an unrealized gain of
$15.8 million.
For the year ended December 31, 2008, settlements of hedging contracts decreased oil and gas
revenues by $20.2 million. For the year ended December 31, 2007, settlements of hedging
contracts increased oil and gas revenues by $9.3 million. Settlements expected to be received
in the next 12 months related to these commodity hedges of $33.6 million are recorded as an
asset in the current portion of the fair value of derivative instruments. Settlements expected
to be received after the next 12 months related to these commodity hedges of $6.5 million are
recorded as an asset in the long-term portion of the fair value of the derivative instruments.
At December 31, 2007, the fair value of the oil and gas commodity derivatives was a short-term asset of $9.5 million and a long-term liability of $12.8 million. As of December
31, 2008 and 2007, $15.7 million and ($8.1 million), respectively, is reflected as an
unrealized gain (loss) in accumulated other comprehensive income (loss). As of December 31,
2008 and 2007, $1.6 million and $0.6 million of ineffectiveness was recorded in other income
(expense).
16
(Continued)
Table of Contents
For the years ended December 31, 2008 and 2007, settlements of derivatives that did not
qualify for hedge accounting resulted in gains of $1.8 million and $17.8 million,
respectively, are included in other income. During 2008 and 2007, the gain (loss) on the fair
value of commodity derivatives that are mark-to-market is $17.5 million and $(23.1 million),
respectively, and is included in other income (expense).
(10)
Fair Value Measurements
The Partnership adopted SFAS No. 157 on January 1, 2008 for the fair value measurements of
financials assets and liabilities. SFAS No. 157 establishes a fair value hierarchy that
prioritizes the inputs to the valuation techniques used to measure fair value. The hierarchy
gives the highest priority to unadjusted quoted prices in active markets for identical assets
or liabilities (Level 1 measurements) and the lowest priority to measurements involving
significant unobservable inputs (Level 3 measurements). The three levels of the fair value
hierarchy are as follows:
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets
or liabilities that the Partnership has the ability to access at the measurement date.
Level 2 inputs are other than quoted prices included with Level 1 that are observable
for the asset or liability, either directly or indirectly.
Level 3 inputs are unobservable inputs for the asset or liability.
The level in the fair value hierarchy with a fair value measurement in its entirety falls is
based on the lowest level of input that is significant to the fair value measurement in its
entirety. The fair value of derivative instruments is determined utilizing pricing models for
significantly similar instruments. The models use a variety of techniques to arrive at fair
value, including quotes and pricing analysis. Inputs to the pricing models include publicly
available prices and forward curves generated from a compilation of data gathered from third
parties. The credit risk adjustments are based on credit ratings. In certain circumstances,
the credit rating represented a significant unobservable input utilized in the valuation.
17
(Continued)
Table of Contents
The following table presents assets and liabilities that are measured at fair value on a
recurring basis (including items that are required to be measured at fair value and items for
which the fair value option has been elected) at December 31, 2008 (in thousands):
Quoted prices
in active
Significant
markets for
other
Significant
identical
observable
unobservable
assets
inputs
inputs
(Level 1)
(Level 2)
(1)
(Level 3)
$
$
40,156
$
$
$
40,156
$
$
$
$
1,940
$
$
$
1,940
(1)
Amounts shown are netted under derivative netting agreements.
The following table presents the Partnerships activity for derivatives measured at fair value
on a recurring basis using significant unobservable inputs (Level 3) as defined by SFAS No.
157 for the year ended December 31, 2008 (in thousands):
Liabilities
Interest rate
derivatives
$
(2,214
)
2,542
(1,918
)
(350
)
$
(1,940
)
18
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
(11)
Other Comprehensive Income (Loss)
December 31,
2008
2007
$
(10,346
)
$
13,862
(18,335
)
9,254
42,137
(31,393
)
23,802
(22,139
)
(2,268
)
84
2,542
(2,153
)
274
(2,069
)
24,076
(24,208
)
$
13,730
$
(10,346
)
(12)
Commitments and Contingencies
19
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
$
360
369
379
289
$
1,397
(13)
Subsequent Events
(a)
Recapitalization and Restructuring of Second Term Lien Loans
On October 13, 2009, the membership interests of the Partnership were transferred to
Dynamic Beryl Holdings, LLC (DBH) through a series of transactions as stated in the
Purchase and Contribution Agreement (the Agreement). DBH is owned by Dynamic Offshore
Resources, LLC (Dynamic), Superior Energy Investments, LLC (Superior), and the Second
Lienholders.
Upon formation of DBH, Dynamic committed to make a capital contribution of $21.9 million
in exchange for a 62% interest in DBH; Superior committed to make capital contributions
of $8.1 million for a 23% interest in DBH; and the Second Lienholders committed to
contribute all
outstanding Second Term Lien Loans (including all principal and accrued interest thereon)
held by it to DBH in exchange for a 15% interest in DBH. The 15% interest is callable by
the Partnership for $50 million for three years following October 13, 2009. After the
contribution of the Second Term Lien Loans to DBH, the Partnership entered into a Second
Lien Amended and Restated Credit Agreement (the Amended Second Lien Agreement) to replace
the First Term Lien Loan.
(b)
Amended Second Lien Agreement
On October 13, 2009, the Partnership entered into the Amended Second Lien Agreement in
conjunction with the transactions under the Agreement, but prior to DBH taking ownership
of the Partnership. The Amended Second Lien Agreement provides that the original
remaining balance of the First Term Lien Loans of $179.1 million, together with accrued
but unpaid interest is converted into term loans in the aggregate principal amount of
$151.2 million (the difference was forgiven by the First Term Lienholders). Immediately
after DBH taking ownership of the Partnership, the Partnership made a mandatory
prepayment under the Amended Second Lien Agreement in the amount of $26.2 million,
leaving a new remaining balance under the Amended Second Lien Agreement of $125.0
million.
The Amended Second Lien Agreement bears interest at a rate equal to the higher of (i)
LIBOR or (ii) 3%, plus a margin of 5%. Interest is payable on the last business day of
March, June, September, and December. The Amended Second Lien Agreement matures on
October 13, 2014. Obligations under the Amended Second Lien Agreement are secured by
second priority liens on substantially all of the Partnerships assets. The Amended
Second Lien Agreement contains customary events of
20
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
default and requires that the
Partnership satisfy various financial covenants, which require the Partnership to: (i)
maintain a leverage ratio, as defined in the Amended Second Lien Agreement; (ii) maintain
an interest coverage ratio, as defined in the Amended Second Lien Agreement; and (iii)
maintain a current ratio, as defined in the Amended Second Lien Agreement. The
requirements to maintain a leverage ratio and an interest coverage ratio do not become
effective until the fiscal quarter ending September 30, 2011. The Amended Second Lien
Agreement also limits the Partnerships ability to pay dividends or make other
distributions, make acquisitions, create liens, and incur additional indebtedness. The
Partnership is also required to enter into commodity price hedging agreements for its
sales of natural gas and oil.
(c)
Revolving Credit Facility
Also, on October 13, 2009, after DBH taking ownership of the Partnership, the Partnership
entered into a revolving credit facility to provide for a three-year $25.0 million
revolving credit facility (the Revolver). The initial borrowing base under the Revolver
was $10.0 million with initial availability of $4.0 million. The full amount available
under the Revolver is also available for the issuance of letters of credit.
The Revolver is subject to semiannual borrowing base redeterminations on April 1 and
October 1 of each year. In addition to the scheduled semiannual borrowing base
redetermination, the lenders or the Partnership have the right to redetermine the
borrowing base at any time, provided that no party can request more than one such
redetermination between the regularly scheduled borrowing base redeterminations. The
determination of our borrowing base is subject to a number of factors, including the
quantities of proved oil and natural gas reserves, the lenders price assumptions and
other various factors, some of which may be out of our control. Our lenders can
redetermine the borrowing base to a lower level than the current borrowing base if they
determine that our oil and natural gas reserves, at the time of redetermination, are
inadequate to support the borrowing base then in effect. In this case, the Partnership
would be required to make three monthly payments each equal to one third of the amount by
which the aggregate outstanding loans and letters of credit exceed the borrowing base.
Obligations under the Revolver are secured by first priority liens on substantially all
of the Partnerships assets. The Revolver also contains other restrictive covenants,
including, among other items, maintenance of a leverage ratio, an interest coverage
ratio, and a current ratio (all as defined in the Revolver), restriction on cash
dividends, and restrictions on incurring additional indebtedness.
21
(Continued)
Table of Contents
Notes to Financial Statements
Unaudited
December 31, 2008 and 2007
22
Table of Contents
Supplemental Information (Unaudited)
December 31, 2008 and 2007
Crude oil
Natural gas
(Mbbls)
(Mmcf)
4,940
88,837
49
9,986
864
(5,747
)
(1,274
)
(17,430
)
4,579
75,646
702
13,011
(472
)
(150
)
(889
)
(11,704
)
3,920
76,803
23
(Continued)
Table of Contents
Supplemental Information (Unaudited)
December 31, 2008 and 2007
Crude oil
Natural gas
(Mbbls)
(Mmcf)
3,937
56,081
3,385
66,752
December 31,
2008
2007
$
$
1,653
389
1,653
389
44,270
5,134
45,630
48,925
$
91,553
$
54,448
1.
Future costs and selling prices will probably differ from those required to be used in these
calculations.
2.
Due to future market conditions and governmental regulations, actual rates of production
achieved in future years may vary significantly from the rate of production assumed in the
calculations.
3.
Selection of a 10% discount rate is required by SFAS No. 69 and may not be reasonable as a
measure of the relative risk inherent in realizing future net oil and gas revenues.
24
(Continued)
Table of Contents
Supplemental Information (Unaudited)
December 31, 2008 and 2007
2008
2007
$
628,444
$
980,942
(171,496
)
(142,559
)
(199,692
)
(199,156
)
257,256
639,227
(58,935
)
(158,461
)
$
198,321
$
480,766
2008
2007
$
480,766
$
370,912
(136,609
)
(185,273
)
(237,276
)
175,181
(35,590
)
(56,596
)
60,475
62,890
(10,473
)
(3,457
)
45,630
54,448
(9,377
)
25,570
40,775
37,091
(282,445
)
109,854
$
198,321
$
480,766
25
Page | ||||||
|
||||||
ARTICLE I PURPOSE AND EFFECTIVE DATE | 1 | |||||
|
||||||
ARTICLE II DEFINITIONS | 1 | |||||
2.01
|
Administrative Committee | 1 | ||||
2.02
|
Base Salary | 1 | ||||
2.03
|
Base Salary Deferral | 1 | ||||
2.04
|
Beneficiary | 1 | ||||
2.05
|
Board | 1 | ||||
2.06
|
Bonus Compensation | 1 | ||||
2.07
|
Business Combination | 1 | ||||
2.08
|
CEO | 2 | ||||
2.09
|
Change of Control | 2 | ||||
2.10
|
Change of Control Participant | 3 | ||||
2.11
|
Claimant | 3 | ||||
2.12
|
Code | 3 | ||||
2.13
|
Common Stock | 3 | ||||
2.14
|
Company | 3 | ||||
2.15
|
Compensation Committee | 3 | ||||
2.16
|
Deferral Account | 4 | ||||
2.17
|
Deferral Period | 4 | ||||
2.18
|
Deferred Amount | 4 | ||||
2.19
|
Designee | 4 | ||||
2.20
|
Disabled | 4 | ||||
2.21
|
Eligible Compensation | 4 | ||||
2.22
|
ERISA | 4 | ||||
2.23
|
Form of Payment | 4 | ||||
2.24
|
401(k) Plan | 4 | ||||
2.25
|
Hardship Withdrawal | 4 | ||||
2.26
|
Hypothetical Investment Benchmark | 4 | ||||
2.27
|
Incumbent Board | 4 | ||||
2.28
|
Key Employee | 5 | ||||
2.29
|
Participant | 5 | ||||
2.30
|
Participation Agreement | 5 | ||||
2.31
|
Plan Year | 5 | ||||
2.32
|
Post Transaction Corporation | 5 | ||||
2.33
|
Retirement | 5 | ||||
2.34
|
Separation from Service | 5 | ||||
2.35
|
Superior | 5 | ||||
2.36
|
Unforeseeable Emergency | 5 | ||||
2.37
|
Valuation Date | 6 | ||||
|
||||||
ARTICLE III PARTICIPATION AND PARTICIPANT ELECTIONS | 6 | |||||
3.01
|
Participation | 6 |
i
Page | ||||||
3.02
|
Participation Agreement Timing and Effective Dates | 6 | ||||
3.03
|
Contents of Participation Agreement | 6 | ||||
3.04
|
Modification or Revocation of Election by Participant | 7 | ||||
|
||||||
ARTICLE IV ELECTIVE DEFERRALS AND VESTING | 8 | |||||
4.01
|
Elective Deferred Compensation | 8 | ||||
4.02
|
Vesting of Deferral Account | 8 | ||||
|
||||||
ARTICLE V MAINTENANCE AND INVESTMENT OF ACCOUNTS | 8 | |||||
5.01
|
Maintenance of Accounts | 8 | ||||
5.02
|
Hypothetical Investment Benchmarks | 8 | ||||
5.03
|
Statement of Accounts | 8 | ||||
|
||||||
ARTICLE VI BENEFITS | 9 | |||||
6.01
|
Time and Form of Payment | 9 | ||||
6.02
|
In-Service Distributions; Effect of Separation from Service | 9 | ||||
6.03
|
Death or Disability | 10 | ||||
6.04
|
Hardship Withdrawals | 10 | ||||
6.05
|
Withholding of Taxes | 10 | ||||
6.06
|
Acceleration of Payment | 10 | ||||
6.07
|
Delay of Payment | 12 | ||||
|
||||||
ARTICLE VII BENEFICIARY DESIGNATION | 13 | |||||
7.01
|
Beneficiary Designation | 13 | ||||
7.02
|
No Beneficiary Designation | 13 | ||||
|
||||||
ARTICLE VIII ADMINISTRATION | 13 | |||||
8.01
|
Administrative Committee Duties | 13 | ||||
8.02
|
Claims Procedure | 14 | ||||
|
||||||
ARTICLE IX AMENDMENT AND TERMINATION OF PLAN | 15 | |||||
9.01
|
Amendment | 15 | ||||
9.02
|
Companys Right to Terminate | 16 | ||||
|
||||||
ARTICLE X MISCELLANEOUS | 16 | |||||
10.01
|
Unfunded Plan | 16 | ||||
10.02
|
Nonassignability | 17 | ||||
10.03
|
Validity and Severability; Code Section 409A | 17 | ||||
10.04
|
Governing Law | 17 | ||||
10.05
|
Employment Status | 17 | ||||
10.06
|
Underlying Plans and Programs | 17 |
ii
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
WITNESSES | SUPERIOR ENERGY SERVICES, INC. | |||||||||
|
||||||||||
/s/ Danna Allo | By: | /s/ Danny R. Young | ||||||||
|
||||||||||
/s/ Gregory A. Rosenstein | Title: Executive Vice President | |||||||||
18
Page | ||||||
|
||||||
ARTICLE I PURPOSE AND EFFECTIVE DATE | 1 | |||||
|
||||||
ARTICLE II DEFINITIONS | 1 | |||||
2.01
|
Account or Accounts | 1 | ||||
2.02
|
Administrative Committee | 1 | ||||
2.03
|
Base Salary | 1 | ||||
2.04
|
Beneficiary | 1 | ||||
2.05
|
Board | 1 | ||||
2.06
|
Bonus Compensation | 1 | ||||
2.07
|
Business Combination | 1 | ||||
2.08
|
Cause | 2 | ||||
2.09
|
CEO | 2 | ||||
2.10
|
Change of Control | 2 | ||||
2.11
|
Change of Control Participant | 3 | ||||
2.12
|
Claimant | 4 | ||||
2.13
|
Code | 4 | ||||
2.14
|
Compensation Committee | 4 | ||||
2.15
|
Common Stock | 4 | ||||
2.16
|
Company | 4 | ||||
2.17
|
Designee | 4 | ||||
2.18
|
Disabled or Disability | 4 | ||||
2.19
|
Discretionary Contributions | 4 | ||||
2.20
|
Effective Date | 4 | ||||
2.21
|
ERISA | 4 | ||||
2.22
|
Form of Payment | 4 | ||||
2.23
|
401(k) Plan | 4 | ||||
2.24
|
Incumbent Board | 4 | ||||
2.25
|
Participant | 4 | ||||
2.26
|
Participation Agreement | 4 | ||||
2.27
|
Plan Year | 5 | ||||
2.28
|
Post Transaction Corporation | 5 | ||||
2.29
|
Retirement Account | 5 | ||||
2.30
|
Retirement Contributions | 5 | ||||
2.31
|
Section 409A Change of Control | 5 | ||||
2.32
|
Separation from Service | 5 | ||||
2.33
|
Superior | 5 | ||||
2.34
|
Valuation Date | 5 | ||||
2.35
|
Year of Service | 5 | ||||
|
||||||
ARTICLE III PARTICIPATION | 5 | |||||
3.01
|
Participation | 5 | ||||
3.02
|
Termination of Participation | 5 | ||||
|
||||||
ARTICLE IV CONTRIBUTIONS | 6 | |||||
4.01
|
Retirement Contributions | 6 | ||||
4.02
|
Discretionary Contributions | 8 |
i
Page | ||||||
|
||||||
4.03
|
Withholding on Contributions | 8 | ||||
|
||||||
ARTICLE V MAINTENANCE OF ACCOUNTS AND EARNINGS | 8 | |||||
5.01
|
Maintenance of Accounts | 8 | ||||
5.02
|
Earnings Allocation | 8 | ||||
5.03
|
Statement of Accounts | 9 | ||||
|
||||||
ARTICLE VI VESTING | 9 | |||||
6.01
|
Vesting Events | 9 | ||||
6.02
|
Forfeiture | 9 | ||||
|
||||||
ARTICLE VII RETIREMENT BENEFIT | 10 | |||||
7.01
|
Retirement Benefit | 10 | ||||
7.02
|
Timing and Manner of Payment | 10 | ||||
7.03
|
Participation Agreement | 11 | ||||
7.04
|
Participation Agreement Timing | 11 | ||||
7.05
|
Modification of Form of Payment | 11 | ||||
7.06
|
Death | 11 | ||||
7.07
|
Acceleration of Payment | 12 | ||||
7.08
|
Delay of Payment | 13 | ||||
|
||||||
ARTICLE VIII ADMINISTRATION | 14 | |||||
8.01
|
Administrative Committee Duties | 14 | ||||
8.02
|
Claims Procedure | 15 | ||||
|
||||||
ARTICLE IX AMENDMENT AND TERMINATION OF PLAN | 16 | |||||
9.01
|
Amendment | 16 | ||||
9.02
|
Companys Right to Terminate | 16 | ||||
|
||||||
ARTICLE X MISCELLANEOUS | 17 | |||||
10.01
|
Unfunded Plan | 17 | ||||
10.02
|
Nonassignability | 18 | ||||
10.03
|
Validity and Severability | 18 | ||||
10.04
|
Governing Law | 18 | ||||
10.05
|
Employment Status | 18 | ||||
10.06
|
Underlying Plans and Programs | 18 |
ii
1
2
3
4
5
Participants Age + Years of | Retirement Contribution | |||
Service | Percentage | |||
0-45
|
2.5 | % | ||
46-55
|
5.0 | % | ||
56-65
|
7.5 | % | ||
66-75
|
10.0 | % | ||
76-85
|
15.0 | % | ||
86-95
|
17.5 | % | ||
96-105
|
20.0 | % | ||
106+
|
25.0 | % |
6
Years of Service | ||||||||||||||||||||||||||||||||
Retirement Contribution Percentage | ||||||||||||||||||||||||||||||||
Age | 1-5 | 6-10 | 11-15 | 16-20 | 21-25 | 26-30 | 31-35 | 36-40 | ||||||||||||||||||||||||
50-54
|
10.0 | % | 10.0 | % | 15.0 | % | 15.0 | % | 20.0 | % | 20.0 | % | 25.0 | % | 25.0 | % | ||||||||||||||||
55-59
|
10.0 | % | 15.0 | % | 15.0 | % | 20.0 | % | 20.0 | % | 25.0 | % | 25.0 | % | 35.0 | % | ||||||||||||||||
60-64
|
15.0 | % | 15.0 | % | 20.0 | % | 20.0 | % | 25.0 | % | 25.0 | % | 35.0 | % | 35.0 | % | ||||||||||||||||
65+
|
15.0 | % | 20.0 | % | 20.0 | % | 25.0 | % | 25.0 | % | 35.0 | % | 35.0 | % | 35.0 | % |
7
$ | 300,000 |
Base Salary
|
||||
200,000 |
Bonus Compensation
|
|||||
|
||||||
$ | 500,000 | |||||
X | 15 | % |
From table at Section 4.01(b)
|
|||
|
||||||
$ | 75,000 |
Retirement Contribution (Credited 1
st
Quarter 2009)
|
8
Years of Service | Vested Percentage | |||
Less than 6
|
0 | % | ||
6
|
20 | % | ||
7
|
40 | % | ||
8
|
60 | % | ||
9
|
80 | % | ||
10 or more
|
100 | % |
9
10
11
12
13
14
15
16
17
18
WITNESSES | SUPERIOR ENERGY SERVICES, INC. | |||||||||
|
||||||||||
/s/ Danna Allo
|
By: | /s/ Danny R. Young | ||||||||
|
|
|
||||||||
/s
/
Gregory A. Rosenstein
|
Title: | Executive Vice President | ||||||||
|
19
STATE OF JURISDICTION | |||
OF INCORPORATION OR | |||
NAME | ORGANIZATION | ||
|
|||
1105 Peters Road, L.L.C.
|
Louisiana | ||
Balance Point Group, B.V.
|
Netherlands | ||
Blowout Tools, Inc.
|
Texas | ||
Concentric Pipe and Tool Rentals, L.L.C.
|
Louisiana | ||
H.B. Rentals, UK, Ltd.
|
United Kingdom | ||
H.B. Rentals, L.C.
|
Louisiana | ||
Hallin Marine Subsea International plc.
|
Isle of Man | ||
International Snubbing Services, L.L.C.
|
Louisiana | ||
Premier Oilfield Rentals Limited
|
Scotland | ||
SESI, L.L.C.
|
Delaware | ||
Southeast Australian Services Pty., Ltd.
|
Australia | ||
Stabil Drill Specialties, L.L.C.
|
Louisiana | ||
Sub-Surface Tools, L.L.C.
|
Louisiana | ||
Superior Energy Services, L.L.C.
|
Louisiana | ||
Warrior Energy Services Corporation
|
Delaware | ||
Wild Well Control, Inc.
|
Texas | ||
Workstrings, L.L.C.
|
Louisiana |
Very truly yours,
|
||||
/s/ DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716 |
||||
1. | I have reviewed this annual report on Form 10-K of Superior Energy Services, Inc.; | |
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 registrants 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 registrants 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 registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of registrants 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 registrants ability to record, process, summarize and report financial information; and | ||
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
/s/ Terence E. Hall | ||||
Terence E. Hall | ||||
Chairman of the Board and Chief Executive Officer
Superior Energy Services, Inc. |
1. | I have reviewed this annual report on Form 10-K of Superior Energy Services, Inc.; | |
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 registrants 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 registrants 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 registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of registrants 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 registrants ability to record, process, summarize and report financial information; and | ||
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
/s/ Robert S. Taylor | ||||
Robert S. Taylor | ||||
Executive Vice President, Treasurer and Chief Financial Officer
Superior Energy Services, Inc. |
1. | the annual report on Form 10-K of the Company for the year ended December 31, 2009 (the Report), as filed with the Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and | |
2. | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Terence E. Hall | ||||
Terence E. Hall | ||||
Chairman of the Board and Chief Executive Officer
Superior Energy Services, Inc. |
1. | the annual report on Form 10-K of the Company for the year ended December 31, 2009 (the Report), as filed with the Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: February 26, 2010
|
|||
|
/s/ Robert S. Taylor | ||
|
|||
|
Robert S. Taylor | ||
|
Executive Vice President, Treasurer and
Chief Financial Officer |
||
|
Superior Energy Services, Inc. |