UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
(Mark
One)
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|
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x
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QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF
THE SECURITIES EXCHANGE ACT OF 1934
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For
the quarterly period ended June 30, 2008
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¨
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF
THE SECURITIES EXCHANGE ACT OF 1934
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For
the transition period from
to
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Commission
File Number
001-10924
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|
CLAYTON
WILLIAMS ENERGY, INC.
|
(Exact
name of registrant as specified in its
charter)
|
Delaware
|
|
75-2396863
|
(State
or other jurisdiction of incorporation or organization)
|
|
(I.R.S.
Employer Identification No.)
|
Six
Desta Drive - Suite 6500
|
|
|
Midland,
Texas
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|
79705-5510
|
(Address
of principal executive offices)
|
|
(Zip
code)
|
Registrant’s
telephone number, including area code:
|
|
(432)
682-6324
|
(Former
name, former address and former fiscal year, if changed since last
report)
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
|
|
x
Yes
|
|
¨
No
|
|
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definition of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
|
|
|
|
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|
Large
accelerated filer
¨
|
|
Accelerated
filer
x
|
|
|
Non-accelerated
filer
¨
|
|
Smaller
reporting company
¨
|
|
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
|
|
¨
Yes
|
|
x
No
|
|
There
were 12,113,898 shares of Common Stock, $.10 par value, of the registrant
outstanding as of August 6,
2008.
|
CLAYTON
WILLIAMS ENERGY, INC
TABLE
OF CONTENTS
PART
I. FINANCIAL INFORMATION
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Page
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Item
1.
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Financial
Statements
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3
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5
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6
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7
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8
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23
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37
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39
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PART
II. OTHER INFORMATION
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40
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40
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40
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42
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CLAYTON
WILLIAM
S ENERGY, INC.
CONSOLIDATED
BALANCE SHEETS
(Dollars
in thousands)
ASSETS
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
17,492
|
|
|
$
|
12,344
|
|
Accounts
receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales,
net
|
|
|
55,904
|
|
|
|
36,698
|
|
Joint interest and other,
net
|
|
|
16,829
|
|
|
|
16,666
|
|
Affiliates
|
|
|
601
|
|
|
|
308
|
|
Inventory
|
|
|
19,770
|
|
|
|
14,348
|
|
Deferred income
taxes
|
|
|
3,581
|
|
|
|
3,581
|
|
Fair value of
derivatives
|
|
|
-
|
|
|
|
7,191
|
|
Assets held for
sale
|
|
|
-
|
|
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|
17,281
|
|
Prepaids and
other
|
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|
10,346
|
|
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3,962
|
|
|
|
|
124,523
|
|
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|
112,379
|
|
|
|
|
|
|
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PROPERTY
AND EQUIPMENT
|
|
|
|
|
|
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Oil and gas properties,
successful efforts
method
|
|
|
1,404,221
|
|
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|
1,374,090
|
|
Natural gas gathering and
processing
systems
|
|
|
17,808
|
|
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|
18,404
|
|
Contract drilling
equipment
|
|
|
90,573
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|
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|
89,956
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|
Other
|
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|
14,619
|
|
|
|
14,505
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|
|
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1,527,221
|
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1,496,955
|
|
Less accumulated depreciation,
depletion and amortization
|
|
|
(760,957
|
)
|
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|
(765,877
|
)
|
Property and equipment,
net
|
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|
766,264
|
|
|
|
731,078
|
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|
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|
|
|
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|
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|
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|
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|
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OTHER
ASSETS
|
|
|
|
|
|
|
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|
Debt issue costs,
net
|
|
|
6,840
|
|
|
|
6,963
|
|
Other
|
|
|
14,814
|
|
|
|
10,676
|
|
|
|
|
21,654
|
|
|
|
17,639
|
|
|
|
$
|
912,441
|
|
|
$
|
861,096
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON
WILLIAMS ENERGY, INC.
CONSOLIDATED
BALANCE SHEETS
(Dollars
in thousands)
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
|
CURRENT
LIABILITIES
|
|
|
|
|
|
|
Accounts
payable:
|
|
|
|
|
|
|
Trade
|
|
$
|
106,961
|
|
|
$
|
72,477
|
|
Oil and gas
sales
|
|
|
28,350
|
|
|
|
24,806
|
|
Affiliates
|
|
|
2,930
|
|
|
|
1,747
|
|
Current maturities of
long-term
debt
|
|
|
18,750
|
|
|
|
22,500
|
|
Fair value of
derivatives
|
|
|
147,506
|
|
|
|
56,929
|
|
Accrued liabilities and
other
|
|
|
10,610
|
|
|
|
10,308
|
|
|
|
|
315,107
|
|
|
|
188,767
|
|
|
|
|
|
|
|
|
|
|
NON-CURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
309,000
|
|
|
|
430,175
|
|
Deferred income
taxes
|
|
|
38,565
|
|
|
|
44,302
|
|
Fair value of
derivatives
|
|
|
47,853
|
|
|
|
-
|
|
Other
|
|
|
35,383
|
|
|
|
37,046
|
|
|
|
|
430,801
|
|
|
|
511,523
|
|
|
|
|
|
|
|
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COMMITMENTS
AND CONTINGENCIES
|
|
|
|
|
|
|
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|
|
|
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|
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STOCKHOLDERS’
EQUITY
|
|
|
|
|
|
|
|
|
Preferred stock, par value
$.10 per share, authorized – 3,000,000
|
|
|
|
|
|
|
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|
shares; none
issued
|
|
|
-
|
|
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|
-
|
|
Common stock, par value $.10
per share, authorized – 30,000,000
|
|
|
|
|
|
|
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|
shares; issued and
outstanding – 12,112,898 shares in 2008
|
|
|
|
|
|
|
|
|
and 11,354,051 shares in
2007
|
|
|
1,211
|
|
|
|
1,135
|
|
Additional paid-in
capital
|
|
|
136,963
|
|
|
|
121,063
|
|
Retained
earnings
|
|
|
21,898
|
|
|
|
35,890
|
|
Accumulated other
comprehensive income, net of tax
|
|
|
6,461
|
|
|
|
2,718
|
|
|
|
|
166,533
|
|
|
|
160,806
|
|
|
|
$
|
912,441
|
|
|
$
|
861,096
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON
WILLIAMS
ENERGY, INC.
CONSOLIDATED
STATEMENTS OF OPERATIONS
(Unaudited)
(Dollars
in thousands, except per share)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
sales
|
|
$
|
134,291
|
|
|
$
|
74,893
|
|
|
$
|
253,210
|
|
|
$
|
136,073
|
|
Natural gas
services
|
|
|
3,553
|
|
|
|
2,909
|
|
|
|
6,091
|
|
|
|
5,563
|
|
Drilling rig
services
|
|
|
12,703
|
|
|
|
14,228
|
|
|
|
27,535
|
|
|
|
22,645
|
|
Gain on sales of property and
equipment
|
|
|
40,721
|
|
|
|
534
|
|
|
|
41,290
|
|
|
|
784
|
|
Total
revenues
|
|
|
191,268
|
|
|
|
92,564
|
|
|
|
328,126
|
|
|
|
165,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS
AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
21,925
|
|
|
|
17,840
|
|
|
|
42,504
|
|
|
|
35,118
|
|
Exploration:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Abandonments and
impairments
|
|
|
1,933
|
|
|
|
23,519
|
|
|
|
2,230
|
|
|
|
34,624
|
|
Seismic and
other
|
|
|
1,562
|
|
|
|
1,580
|
|
|
|
5,237
|
|
|
|
2,470
|
|
Natural gas
services
|
|
|
3,244
|
|
|
|
2,904
|
|
|
|
5,759
|
|
|
|
5,317
|
|
Drilling rig
services
|
|
|
9,923
|
|
|
|
8,506
|
|
|
|
21,040
|
|
|
|
13,439
|
|
Depreciation, depletion and
amortization
|
|
|
24,974
|
|
|
|
18,487
|
|
|
|
55,247
|
|
|
|
33,718
|
|
Impairment of property and
equipment
|
|
|
-
|
|
|
|
479
|
|
|
|
-
|
|
|
|
1,044
|
|
Accretion of abandonment
obligations
|
|
|
485
|
|
|
|
619
|
|
|
|
1,015
|
|
|
|
1,237
|
|
General and
administrative
|
|
|
7,944
|
|
|
|
4,932
|
|
|
|
11,392
|
|
|
|
8,835
|
|
Loss on sales of property and
equipment
|
|
|
277
|
|
|
|
-
|
|
|
|
286
|
|
|
|
9,323
|
|
Total costs and
expenses
|
|
|
72,267
|
|
|
|
78,866
|
|
|
|
144,710
|
|
|
|
145,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
119,001
|
|
|
|
13,698
|
|
|
|
183,416
|
|
|
|
19,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
(6,077
|
)
|
|
|
(7,986
|
)
|
|
|
(13,523
|
)
|
|
|
(15,615
|
)
|
Gain (loss) on
derivatives
|
|
|
(148,587
|
)
|
|
|
6,110
|
|
|
|
(194,696
|
)
|
|
|
(10,739
|
)
|
Other
|
|
|
3,014
|
|
|
|
3,614
|
|
|
|
3,669
|
|
|
|
4,327
|
|
Total other income
(expense)
|
|
|
(151,650
|
)
|
|
|
1,738
|
|
|
|
(204,550
|
)
|
|
|
(22,027
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before income taxes
|
|
|
(32,649
|
)
|
|
|
15,436
|
|
|
|
(21,134
|
)
|
|
|
(2,087
|
)
|
Income
tax (expense)
benefit
|
|
|
11,642
|
|
|
|
(5,357
|
)
|
|
|
7,420
|
|
|
|
723
|
|
Minority
interest, net of
tax
|
|
|
(164
|
)
|
|
|
(1,269
|
)
|
|
|
(278
|
)
|
|
|
(2,136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
(LOSS)
|
|
$
|
(21,171
|
)
|
|
$
|
8,810
|
|
|
$
|
(13,992
|
)
|
|
$
|
(3,500
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.75
|
)
|
|
$
|
0.78
|
|
|
$
|
(1.19
|
)
|
|
$
|
(0.31
|
)
|
Diluted
|
|
$
|
(1.75
|
)
|
|
$
|
0.77
|
|
|
$
|
(1.19
|
)
|
|
$
|
(0.31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
12,111
|
|
|
|
11,352
|
|
|
|
11,749
|
|
|
|
11,236
|
|
Diluted
|
|
|
12,111
|
|
|
|
11,507
|
|
|
|
11,749
|
|
|
|
11,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON
W
ILLIAM
S ENERGY, INC.
CONSOLIDATED
STATEMENT OF STOCKHOLDERS' EQUITY
(Unaudited)
(Dollars
in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Total
|
|
|
|
Common
Stock
|
|
|
Additional
|
|
|
|
|
|
Compre-
|
|
|
Compre-
|
|
|
|
No.
of
|
|
|
Par
|
|
|
Paid-In
|
|
|
Retained
|
|
|
hensive
|
|
|
hensive
|
|
|
|
Shares
|
|
|
Value
|
|
|
Capital
|
|
|
Earnings
|
|
|
Income
|
|
|
Loss
|
|
BALANCE,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2007
|
|
|
11,354
|
|
|
$
|
1,135
|
|
|
$
|
121,063
|
|
|
$
|
35,890
|
|
|
$
|
2,718
|
|
|
|
|
Net
loss
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(13,992
|
)
|
|
|
-
|
|
|
$
|
(13,992
|
)
|
Unrealized gain
on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
marketable
securities,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net of tax of
$2,015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,743
|
|
|
|
3,743
|
|
Total
comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(10,249
|
)
|
Issuance of stock
through
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
plans
|
|
|
759
|
|
|
|
76
|
|
|
|
15,900
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
BALANCE,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2008
|
|
|
12,113
|
|
|
$
|
1,211
|
|
|
$
|
136,963
|
|
|
$
|
21,898
|
|
|
$
|
6,461
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON
WILLIAMS ENERGY
, INC.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Unaudited)
(Dollars
in thousands)
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(13,992
|
)
|
|
$
|
(3,500
|
)
|
Adjustments to reconcile net
loss to cash
|
|
|
|
|
|
|
|
|
provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
55,247
|
|
|
|
33,718
|
|
Impairment of property and
equipment
|
|
|
-
|
|
|
|
1,044
|
|
Exploration
costs
|
|
|
2,230
|
|
|
|
34,624
|
|
(Gain) loss on sales of
property and equipment, net
|
|
|
(41,004
|
)
|
|
|
8,539
|
|
Deferred income
taxes
|
|
|
(7,752
|
)
|
|
|
(723
|
)
|
Non-cash employee
compensation
|
|
|
1,910
|
|
|
|
1,110
|
|
Unrealized loss on
derivatives
|
|
|
145,621
|
|
|
|
11,236
|
|
Settlements on derivatives with
financing elements
|
|
|
24,789
|
|
|
|
12,005
|
|
Amortization of debt issue
costs
|
|
|
785
|
|
|
|
625
|
|
Accretion of abandonment
obligations
|
|
|
1,015
|
|
|
|
1,237
|
|
Minority interest, net of
tax
|
|
|
278
|
|
|
|
2,136
|
|
|
|
|
|
|
|
|
|
|
Changes in operating working
capital:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(19,662
|
)
|
|
|
(10,657
|
)
|
Accounts
payable
|
|
|
398
|
|
|
|
(1,005
|
)
|
Other
|
|
|
(442
|
)
|
|
|
(453
|
)
|
Net cash provided by operating
activities
|
|
|
149,421
|
|
|
|
89,936
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Additions to property and
equipment
|
|
|
(118,491
|
)
|
|
|
(120,435
|
)
|
Additions to equipment of
Larclay
JV.
|
|
|
(9
|
)
|
|
|
(23,415
|
)
|
Proceeds from sales of property
and
equipment
|
|
|
114,049
|
|
|
|
1,602
|
|
Change in equipment
inventory
|
|
|
(6,777
|
)
|
|
|
11,835
|
|
Other
|
|
|
785
|
|
|
|
(8,269
|
)
|
Net cash used in investing
activities
|
|
|
(10,443
|
)
|
|
|
(138,682
|
)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
Proceeds from long-term
debt
|
|
|
-
|
|
|
|
40,500
|
|
Proceeds from long-term debt of
Larclay
JV
|
|
|
4,000
|
|
|
|
8,727
|
|
Repayments of long-term
debt
|
|
|
(115,800
|
)
|
|
|
-
|
|
Repayments of long-term debt of
Larclay
JV
|
|
|
(13,125
|
)
|
|
|
-
|
|
Proceeds from exercise of stock
options
|
|
|
15,884
|
|
|
|
5,970
|
|
Settlements on derivatives with
financing
elements
|
|
|
(24,789
|
)
|
|
|
(12,005
|
)
|
Net cash provided by (used in)
financing activities
|
|
|
(133,830
|
)
|
|
|
43,192
|
|
|
|
|
|
|
|
|
|
|
NET
INCREASE (DECREASE) IN CASH AND
|
|
|
|
|
|
|
|
|
CASH
EQUIVALENTS
|
|
|
5,148
|
|
|
|
(5,554
|
)
|
|
|
|
|
|
|
|
|
|
CASH
AND CASH EQUIVALENTS
|
|
|
|
|
|
|
|
|
Beginning of
period
|
|
|
12,344
|
|
|
|
13,840
|
|
End of
period
|
|
$
|
17,492
|
|
|
$
|
8,286
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURES
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of
amounts
capitalized
|
|
$
|
13,123
|
|
|
$
|
15,283
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON WILLIAMS
ENERGY, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
June
30, 2008
(Unaudited)
1.
Nature of Operations
Clayton
Williams Energy, Inc. (a Delaware corporation) and its subsidiaries
(collectively, the “Company” or “CWEI”) is an independent oil and gas company
engaged in the exploration for and development and production of oil and natural
gas primarily in its core areas in Texas, Louisiana and New
Mexico. Approximately 26% of the Company’s outstanding common stock
is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”),
Chairman of the Board and Chief Executive Officer of the Company, and
approximately 25% is owned by a partnership in which Mr. Williams’ adult
children are limited partners.
Substantially
all of the Company’s oil and gas production is sold under short-term contracts
which are market-sensitive. Accordingly, the Company’s financial
condition, results of operations, and capital resources are highly dependent
upon prevailing market prices of, and demand for, oil and natural
gas. These commodity prices are subject to wide fluctuations and
market uncertainties due to a variety of factors that are beyond the control of
the Company. These factors include the level of global demand for
petroleum products, foreign supply of oil and gas, the establishment of and
compliance with production quotas by oil-exporting countries, the strength of
the U.S. dollar, weather conditions, the price and availability of alternative
fuels, and overall economic conditions, both foreign and domestic.
2.
Presentation
The
preparation of these consolidated financial statements in conformity with
accounting principles generally accepted in the United States requires
management of the Company to make 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 periods. Actual results
could differ materially from those estimates.
The
consolidated financial statements include the accounts of Clayton Williams
Energy, Inc., its wholly-owned subsidiaries and the accounts of the Larclay JV
(see Note 11). The Company also accounts for its undivided interests
in oil and gas limited partnerships using the proportionate consolidation
method. Under this method, the Company consolidates its proportionate
share of assets, liabilities, revenues and expenses of these limited
partnerships utilizing accounting policies followed by the
Company. Less than 5% of the Company’s consolidated total assets and
total revenues are derived from oil and gas limited partnerships. All
significant intercompany transactions and balances associated with the
consolidated operations have been eliminated.
In the
opinion of management, the Company's unaudited consolidated financial statements
as of June 30, 2008 and for the interim periods ended June 30, 2008 and 2007
include all adjustments which are necessary for a fair presentation in
accordance with accounting principles generally accepted in the United
States. These interim results are not necessarily indicative of the
results to be expected for the year ending December 31, 2008.
Certain
information and footnote disclosures normally included in financial statements
prepared in accordance with accounting principles generally accepted in the
United States have been condensed or omitted in this Form 10-Q pursuant to the
rules and regulations of the Securities and Exchange Commission
(“SEC”). These consolidated financial statements should be read in
conjunction with the audited consolidated financial statements and notes thereto
included in the Company's Form 10-K for the year ended December 31,
2007.
3.
Recent Accounting Pronouncements
In March
2008, the Financial Accounting Standards Board (“FASB”) issued SFAS
No. 161,
“Disclosures
about Derivative Instruments and Hedging Activities, an amendment of FASB
Statement No. 133”
(“SFAS 161”). This statement is intended to
improve transparency in financial reporting by requiring enhanced disclosures of
an entity’s derivative instruments and hedging activities and their effects on
the entity’s financial position, financial performance, and cash flows. SFAS 161
applies to all derivative instruments within the scope of SFAS 133 as well as
related hedged items, bifurcated derivatives, and non-derivative instruments
that are designated and qualify as hedging instruments. Entities with
instruments subject to SFAS 161 must provide more robust qualitative disclosures
and expanded quantitative disclosures. SFAS 161 is effective prospectively for
financial statements issued for fiscal years and interim periods beginning after
November 15, 2008, with early application permitted. The Company
is currently evaluating the disclosure implications of this
statement.
In
December 2007, the FASB issued SFAS 141R,
“Business Combinations”
(“SFAS 141R”) and SFAS 160,
“Noncontrolling Interests in
Consolidated Financial Statements”
(“SFAS 160”). SFAS 141R
requires most identifiable assets, liabilities, noncontrolling interests, and
goodwill acquired in a business combination to be recorded at “fair value.” The
Statement applies to all business combinations, including combinations among
mutual entities and combinations by contract alone. Under SFAS 141R, all
business combinations will be accounted for by applying the acquisition method.
SFAS 141R is effective for periods beginning on or after December 15,
2008. SFAS 160 will require noncontrolling interests (previously referred
to as minority interests) to be treated as a separate component of equity, not
as a liability or other item outside of permanent equity. The
statement applies to the accounting for noncontrolling interests and
transactions with noncontrolling interest holders in consolidated financial
statements. SFAS 160 is effective for periods beginning on or after
December 15, 2008 and will be applied prospectively to all noncontrolling
interests, including any that arose before the effective date except that
comparative period information must be recast to classify noncontrolling
interests in equity, attribute net income and other comprehensive income to
noncontrolling interests, and provide other disclosures required by
SFAS 160. The impact to the Company from the adoption of SFAS
141R in 2009 will depend on future acquisition activity.
4.
Long-Term Debt
Long-term
debt consists of the following:
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
7¾%
Senior Notes, due
2013
|
|
$
|
225,000
|
|
|
$
|
225,000
|
|
Secured
bank credit facility, due May
2012
|
|
|
50,000
|
|
|
|
165,800
|
|
Secured
term loan of Larclay JV, due June
2011
|
|
|
52,750
|
|
|
|
61,875
|
|
|
|
|
327,750
|
|
|
|
452,675
|
|
Less
current maturities
(a)
|
|
|
(18,750
|
)
|
|
|
(22,500
|
)
|
|
|
$
|
309,000
|
|
|
$
|
430,175
|
|
|
|
|
|
|
|
|
|
|
(a) Consists
of current portion of term loan of Larclay JV.
|
|
|
|
|
|
|
|
|
7¾% Senior Notes due
2013
In July
2005, the Company issued, in a private placement, $225 million of aggregate
principal amount of 7¾% Senior Notes due 2013 (“Senior Notes”). The
Senior Notes were issued at face value and bear interest at 7¾% per year,
payable semi-annually on February 1 and August 1 of each year, beginning
February 1, 2006.
At any
time prior to August 1, 2008, the Company may redeem up to 35% of the aggregate
principal amount of the Senior Notes with the proceeds of certain equity
offerings at a redemption price of 107.75% of the principal amount, plus accrued
and unpaid interest. In addition, prior to August 1, 2009, the
Company may redeem some or all of the Senior Notes at a redemption price equal
to 100% of the principal amount of the Senior Notes to be redeemed, plus a
make-whole premium, plus any accrued and unpaid interest. On and
after August 1, 2009, the Company may redeem some or all of the Senior Notes at
redemption prices (expressed as percentages of principal amount) equal to
103.875% for the twelve-month period beginning on August 1, 2009, 101.938%
for the
twelve-month
period beginning on August 1, 2010, and 100.00% beginning on August 1, 2011 or
for any period thereafter, in each case plus accrued and unpaid
interest.
The
Indenture governing the Senior Notes restricts the ability of the Company and
its restricted subsidiaries to: (i) borrow money;
(ii) issue redeemable or preferred stock; (iii) pay distributions or
dividends; (iv) make investments; (v) create liens without securing
the Senior Notes; (vi) enter into agreements that restrict dividends from
subsidiaries; (vii) sell certain assets or merge with or into other
companies; (viii) enter into transactions with affiliates;
(ix) guarantee indebtedness; and (x) enter into new lines of
business. The Company was in compliance with these covenants at June
30, 2008.
Secured Bank Credit
Facility
The
Company’s secured bank credit facility provides for a revolving loan facility in
an amount not to exceed the lesser of the borrowing base, as established by the
banks, or that portion of the borrowing base determined by the Company to be the
elected borrowing limit. The borrowing base, which is based on the
discounted present value of future net revenues from oil and gas production, is
subject to redetermination at any time, but at least semi-annually in May and
November, and is made at the discretion of the banks. If, at any time, the
redetermined borrowing base is less than the amount of outstanding indebtedness,
the Company will be required to (i) pledge additional collateral, (ii) prepay
the excess in not more than five equal monthly installments, or (iii) elect to
convert the entire amount of outstanding indebtedness to a term obligation based
on amortization formulas set forth in the loan agreement. Substantially
all of the Company’s oil and gas properties are pledged to secure advances under
the credit facility. The borrowing base was reduced in May 2008 from
$275 million to $250 million in connection with our sale of certain
properties in South Louisiana. In June 2008, we elected to hold the
borrowing base at $250 million instead of increasing it to levels supported by
the collateral values assigned by the banks. After allowing for
outstanding letters of credit totaling $804,000, the Company had
$199.2 million available under the credit facility at June 30,
2008.
The
revolving credit facility provides for interest at rates based on the agent
bank’s prime rate plus margins ranging from .25% to 1%, or if elected by the
Company based on LIBOR plus margins ranging from 1.5% to 2.25%. The
Company also pays a commitment fee on the unused portion of the revolving credit
facility. Interest and fees are payable at least
quarterly. The effective annual interest rate on borrowings under the
combined credit facility, excluding bank fees and amortization of debt issue
costs, for the six months ended June 30, 2008 was 5.2%.
The loan
agreement applicable to the revolving credit facility contains financial
covenants that are computed quarterly. The working capital covenant
requires the Company to maintain a ratio of current assets to current
liabilities of at least 1 to 1. Another financial covenant under the
credit facility requires the Company to maintain a ratio of indebtedness to cash
flow of no more than 3 to 1. The computations of current assets,
current liabilities, cash flow and indebtedness are defined in the loan
agreement. The Company was in compliance with all financial and
non-financial covenants at June 30, 2008.
Secured Term Loan of Larclay
JV
In
connection with the Company’s investment in Larclay JV (see Note 11), Larclay JV
obtained a $75 million secured term loan facility from a lender to finance
the construction and equipping of 12 new drilling rigs. The Larclay
JV term loan is secured by substantially all of the assets of Larclay
JV. Initially, the Company pledged additional collateral in the form
of a $19 million letter of credit. In February 2007, the letter
of credit was cancelled and replaced by a $19.5 million guaranty from the
Company. Although the Company is not a maker on the Larclay JV
term loan, it is providing partial credit support for the Larclay JV term
loan and is required to fully consolidate the accounts of Larclay JV under FASB
Interpretation No. 46R
“Consolidation of Variable Interest
Entities – an Interpretation of ARB No. 51 (as amended)”
(“FIN
46R”).
The
Larclay JV term loan, as amended, bears interest at a floating rate based on a
LIBOR average, plus 3.25%, and provides for monthly interest payments through
June 2007 and monthly principal and interest payments thereafter sufficient to
retire the principal balance by 35% in the first year, 25% in each of the next
two years, and 15% in the fourth year. Two voluntary prepayments of
$10 million each may be made in 2008 and 2009 without a prepayment
penalty. The Larclay JV term loan prohibits Larclay JV from making
any cash distributions to the Company or Lariat until the balance on the term
loan is fully repaid, and repayments by Larclay JV of any loans by the Company
or Lariat are subordinated to the loans outstanding under the term loan and are
subject to other restrictions. At June 30, 2008, the effective
interest rate on the Larclay JV term loan was 6.6%.
5.
Other Non-Current Liabilities
Other
non-current liabilities consist of the following:
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Abandonment
obligations
|
|
$
|
29,062
|
|
|
$
|
30,994
|
|
Minority interest, net of
tax
|
|
|
5,164
|
|
|
|
4,886
|
|
Other taxes
payable
|
|
|
358
|
|
|
|
358
|
|
Other
|
|
|
799
|
|
|
|
808
|
|
|
|
$
|
35,383
|
|
|
$
|
37,046
|
|
Changes
in abandonment obligations for the six months ended June 30, 2008 and 2007 are
as follows:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Beginning of
period
|
|
$
|
30,994
|
|
|
$
|
27,846
|
|
Additional abandonment
obligations from new
wells
|
|
|
228
|
|
|
|
451
|
|
Sales of
properties
|
|
|
(1,784
|
)
|
|
|
(1,036
|
)
|
Revisions of previous
estimates
|
|
|
(1,391
|
)
|
|
|
-
|
|
Accretion
expense
|
|
|
1,015
|
|
|
|
1,237
|
|
End of
period
|
|
$
|
29,062
|
|
|
$
|
28,498
|
|
6.
Compensation Plans
Stock-Based
Compensation
The
Company has reserved 1,798,200 shares of common stock for issuance under the
1993 Stock Compensation Plan (“1993 Plan”). The 1993 Plan provides
for the issuance of nonqualified stock options with an exercise price which is
not less than the market value of the Company’s common stock on the date of
grant. All options granted through June 30, 2008 expire 10 years from
the date of grant and become exercisable based on varying vesting
schedules. The Company issues new shares, not repurchased shares, to
option holders that exercise stock options under the 1993 Plan. At
June 30, 2008, 101,766 shares remain available for issuance under this
plan.
The
Company has reserved 86,300 shares of common stock for issuance under the
Outside Directors Stock Option Plan (“Directors Plan”). Since the
inception of the Directors Plan, the Company has issued options covering 52,000
shares of common stock at option prices ranging from $3.25 to $41.74 per
share. All outstanding options expire 10 years from the grant date
and are fully exercisable upon issuance. At June 30, 2008, 34,300
shares remain available for issuance under this plan.
The
following table sets forth certain information regarding the Company’s stock
option plans as of and for the six months ended June 30, 2008:
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
|
|
|
Exercise
|
|
|
Contractual
|
|
|
Intrinsic
|
|
|
|
Shares
|
|
|
Price
|
|
|
Term
|
|
|
Value
(a)
|
|
Outstanding
at January 1, 2008
|
|
|
811,485
|
|
|
$
|
20.49
|
|
|
|
|
|
|
|
Granted
|
|
|
4,000
|
|
|
$
|
31.16
|
|
|
|
|
|
|
|
Exercised (b)
|
|
|
(758,847
|
)
|
|
$
|
20.93
|
|
|
|
|
|
|
|
Outstanding
at June 30, 2008
|
|
|
56,638
|
|
|
$
|
15.30
|
|
|
|
3.16
|
|
|
$
|
5,360,715
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested
at June 30, 2008
|
|
|
56,638
|
|
|
$
|
15.30
|
|
|
|
3.16
|
|
|
$
|
5,360,715
|
|
Exercisable
at June 30, 2008
|
|
|
56,638
|
|
|
$
|
15.30
|
|
|
|
3.16
|
|
|
$
|
5,360,715
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Based on closing
price at June 30, 2008 of $109.95 per share.
|
|
(b)
Cash received for
options exercised totaled $15.9 million.
|
|
The
following table summarizes information with respect to options outstanding at
June 30, 2008, all of which are currently exercisable.
|
Outstanding
and Exercisable Options
|
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
Average
|
|
|
|
Average
|
|
Remaining
|
|
|
|
Exercise
|
|
Life
in
|
|
Shares
|
|
Price
|
|
Years
|
Range
of exercise prices:
|
|
|
|
|
|
$5.50
|
27,638
|
|
$
5.50
|
|
0.8
|
$10.00 -
$19.74
|
10,000
|
|
$
11.93
|
|
2.8
|
$22.90 -
$41.74
|
19,000
|
|
$
31.33
|
|
6.8
|
|
56,638
|
|
$
15.30
|
|
3.2
|
The
following table presents certain information regarding stock-based compensation
amounts for the six months ended June 30, 2008 and 2007.
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands, except per share)
|
|
Weighted
average grant date fair value of options granted per share
|
|
$
|
23.06
|
|
|
$
|
27.56
|
|
Intrinsic
value of options exercised
|
|
$
|
20,344
|
|
|
$
|
228
|
|
|
|
|
|
|
|
|
|
|
Stock-based
employee compensation expense
|
|
$
|
92
|
|
|
$
|
110
|
|
Tax
benefit
|
|
|
(32
|
)
|
|
|
(39
|
)
|
Net
stock-based employee compensation expense
|
|
$
|
60
|
|
|
$
|
71
|
|
After-Payout Incentive
Plan
The
Compensation Committee of the Board of Directors has adopted an incentive plan
for officers, key employees and consultants who promote the Company’s drilling
and acquisition programs. Management’s objective in adopting this
plan is to further align the interests of the participants with those of the
Company by granting the participants an after-payout interest in the production
developed, directly or indirectly, by the participants. The plan
generally provides for the creation of a series of partnerships or participation
arrangements (“APO Arrangements”) between the Company and the participants to
which the Company contributes a portion of its economic interest in wells
drilled or acquired within certain areas. Generally, the Company pays
all costs to acquire, drill and produce applicable wells and receives all
revenues until it has recovered all of its costs, plus interest
(“payout”). At payout, the participants receive 99% to 100% of all
subsequent revenues and pay 99% to 100% of all subsequent expenses attributable
to the APO Arrangements.
Between
3% and 7.5% of the Company’s economic interests in specified wells drilled or
acquired by the Company subsequent to October 2002 are subject to APO
Arrangements (excluding properties acquired in a merger with Southwest
Royalties, Inc. in May 2004). The Company records its allocable share
of the assets, liabilities, revenues, expenses and oil and gas reserves of these
APO Arrangements in its consolidated financial statements. The
Company recognized $1.8 million of non-cash compensation expense during the
six-month period ended June 30, 2008 and $1 million for the six-month
period ended June 30, 2007 for the estimated fair value of the APO Arrangements
granted during those periods.
Reward
Plans
The
Company has created four bonus plans designed to reward eligible officers,
employees and other service providers for continued quality service to the
Company, and to encourage retention of those persons by providing them the
opportunity to receive bonus payments that are based on profits derived from a
portion of the Company’s working interest in certain wells drilled by the
Company.
One bonus
plan was activated in January 2007 and established a quarterly bonus amount
equal to the after-payout cash flow from a 22.5% working interest in one
well. Under the plan, two-thirds of the quarterly bonus amount is
payable to the participants until the full vesting date of October 25,
2011. After the full vesting date, the deferred portion of the
quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all
subsequent quarterly bonus amounts, are payable to participants.
In June
2008, the Company activated three additional bonus plans. Each of
these plans establishes a quarterly bonus amount equal to 7% of the after-payout
cash flow from wells drilled in the respective plan areas after the effective
date set forth in each plan, which dates range from January 1, 2007 to May 5,
2008. Under these plans, 100% of the quarterly bonus amount is
payable to the participants, and the full vesting date is May 5,
2013.
The
quarterly bonus amount in these plans is allocated among the participants based
on each participant’s bonus percentage. To continue as a participant
in the plans, participants must remain in the employment or service of the
Company through the full vesting date. Participants who remain in the
employment or service of the Company through the full vesting date will continue
as participants for the duration of the plans, subject to certain
restrictions. The full vesting date may be accelerated in the event
of a change of control or sale transaction, as defined in the plan
documents.
The
Company recognizes compensation expense related to these bonus plans over the
vesting period. The Company recorded compensation expense of $438,000
for the six months ended June 30, 2008, and $72,000 for the six months ended
June 30, 2007, in connection with these bonus plans.
7.
Derivatives
Commodity
Derivatives
From time
to time, the Company utilizes commodity derivatives, consisting of swaps, floors
and collars, to attempt to optimize the price received for its oil and gas
production. When using swaps to hedge oil and natural gas production,
the Company receives a fixed price for the respective commodity and pays a
floating market price as defined in each contract (generally NYMEX futures
prices), resulting in a net amount due to or from the
counterparty. In floor transactions, the Company receives a fixed
price (put strike price) if the market price falls below the put strike price
for the respective commodity. If the market price is greater than the
put strike price, no payments are due from either party. Costless
collars are a combination of puts and calls, and contain a fixed floor price
(put strike price) and ceiling price (call strike price). If the
market price for the respective commodity exceeds the call strike price or falls
below the put strike price, then the Company receives the fixed price and pays
the market price. If the market price is between the call and the put
strike prices, no payments are due from either party. Commodity
derivatives are settled monthly as the contract production periods
mature.
The
following summarizes information concerning the Company’s net positions in open
commodity derivatives applicable to periods subsequent to June 30,
2008. The settlement prices of commodity derivatives are based on
NYMEX futures prices.
Collars:
|
|
Gas
|
|
|
Oil
|
|
|
|
MMBtu
(a)
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Bbls
|
|
|
Floor
|
|
|
Ceiling
|
|
Production
Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
rd
Quarter 2008
|
|
|
419,000
|
|
|
$
|
4.00
|
|
|
$
|
5.15
|
|
|
|
128,000
|
|
|
$
|
23.00
|
|
|
$
|
25.07
|
|
Swaps:
|
|
Gas
|
|
|
Oil
|
|
|
|
MMBtu
(a)
|
|
|
Price
|
|
|
Bbls
|
|
|
Price
|
|
Production
Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
3
rd
Quarter 2008
|
|
|
4,000,000
|
|
|
$
|
9.19
|
|
|
|
310,000
|
|
|
$
|
78.96
|
|
4
th
Quarter
2008
|
|
|
4,100,000
|
|
|
$
|
9.17
|
|
|
|
400,000
|
|
|
$
|
82.21
|
|
2009
|
|
|
3,600,000
|
|
|
$
|
9.33
|
|
|
|
1,440,000
|
|
|
$
|
85.30
|
|
|
|
|
11,700,000
|
|
|
|
|
|
|
|
2,150,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
One MMBtu equals
one Mcf at a Btu factor of 1,000.
|
|
In July
2008, the Company terminated certain fixed-price gas swaps covering 300,000
MMBtu at a price of $10.32 per MMBtu from August 2008 through October 2008,
resulting in an aggregate loss of $585,000, which will be paid to the
counterparty monthly as the applicable contracts are settled.
In
September 2007, the Company terminated certain fixed-priced oil swaps covering
60,000 barrels at a price of $76.65 from July 2008 through December 2008,
resulting in an aggregate loss of approximately $663,000, which will be paid to
the counterparty monthly as the applicable contracts are settled.
Interest Rate
Derivative
At June
30, 2008, the Company was a party to one interest rate swap. Under
this derivative, the Company pays a fixed rate for the notional principal
balance and receives a floating market rate based on LIBOR. The
interest rate swap is settled quarterly. The following summarizes
information concerning the Company’s interest rate swap at June 30,
2008.
Interest
Rate Swap:
|
|
|
|
|
Fixed
|
|
|
|
Principal
|
|
|
Libor
|
|
|
|
Balance
|
|
|
Rates
|
|
Period:
|
|
|
|
|
|
|
July 1, 2008 to November 3,
2008
|
|
$
|
45,000,000
|
|
|
|
5.73
|
%
|
In April
2008, the Company terminated its $100 million interest rate swap for a cash
payment of $899,000.
Accounting For
Derivatives
The
Company accounts for its derivatives in accordance with SFAS 133. The
Company did not designate any of its currently open commodity or interest rate
derivatives as cash flow hedges; therefore, all changes in the fair value of
these contracts prior to maturity, plus any realized gains or losses at
maturity, are recorded as other income (expense) in the Company’s statements of
operations. For the six months ended June 30, 2008, the Company
reported a $194.7 million net loss on derivatives, consisting of a
$145.6 million loss related to changes in mark-to-market valuations and a
$49.1 million realized loss for settled contracts. For the six
months ended June 30, 2007, the Company reported a $10.7 million loss on
derivatives, consisting of an $11.2 million loss related to changes in
mark-to-market valuations, net of a $500,000 realized gain on settled
contracts.
8.
Financial Instruments
Cash and
cash equivalents, receivables, accounts payable and accrued liabilities were
each estimated to have a fair value approximating the carrying amount due to the
short maturity of those instruments. Indebtedness under the Company’s
secured bank credit facility was estimated to have a fair value approximating
the carrying amount since the interest rate is generally market
sensitive. The estimated fair value of the Company’s Senior Notes at
June 30, 2008 and December 31, 2007 was approximately $216 million and
$196.9 million, respectively, based on market valuations.
Determination of Fair
Value
The
Company adopted SFAS No. 157,
“Fair Value Measurements”
(“SFAS 157”) (as amended) effective January 1, 2008. SFAS 157 defines
fair value, establishes a framework for measuring fair value, outlines a fair
value hierarchy based on the quality of inputs used to measure fair value and
enhances disclosure requirements for fair value measurements. As
permitted by FSP No. 157-2, the Company has not applied the provisions of SFAS
157 to nonfinancial assets and liabilities. The Company has not
applied the provisions of SFAS 157 to its asset retirement
obligations.
Fair
value is defined as the price at which an asset could be exchanged in a current
transaction between knowledgeable, willing parties at the measurement date.
Where available, fair value is based on observable market prices or parameters
or derived from such prices or parameters. Where observable prices or inputs are
not available, use of unobservable prices or inputs are used to estimate the
current fair value, often using an internal valuation model. These valuation
techniques involve some level of management estimation and judgment, the degree
of which is dependent on the item being valued.
In
accordance with SFAS 157, the Company categorizes its assets and liabilities
recorded at fair value in the accompanying consolidated balance sheets based
upon the level of judgment associated with the inputs used to measure their fair
value. Hierarchical levels, defined by SFAS 157 and directly related to the
amount of subjectivity associated with the inputs to fair valuation of these
assets and liabilities, are as follows:
Level 1
-
|
Inputs
are unadjusted, quoted prices in active markets for identical assets or
liabilities at the measurement
date.
|
Level 2
-
|
Inputs
(other than quoted prices included in Level 1) are either directly or
indirectly observable for the asset or liability through correlation with
market data at the measurement date and for the duration of the
instrument’s anticipated life.
|
Level 3
-
|
Inputs
reflect management’s best estimate of what market participants would use
in pricing the asset or liability at the measurement date. Consideration
is given to the risk inherent in the valuation technique and the risk
inherent in the inputs to the
model.
|
The fair
value of the Company’s investment in common stock of SandRidge is measured using
Level 1 inputs, and is determined by market prices on an active
market.
The fair
value of derivative contracts are measured using Level 2 inputs, and are
determined by either market prices on an active market for similar assets or by
prices quoted by a broker or other market-corroborated prices.
The
estimated fair values of assets and liabilities included in the accompanying
consolidated balance sheets at June 30, 2008 and December 31, 2007 are
summarized below.
|
|
Fair
Value Measurements
|
|
|
|
June
30, 2008
|
|
|
December 31,
2007
|
|
|
|
Quoted
Prices In
|
|
|
Significant
|
|
|
Quoted
Prices In
|
|
|
Significant
|
|
|
|
Active
Markets For
|
|
|
Other
|
|
|
Active
Markets For
|
|
|
Other
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Identical
|
|
|
Observable
|
|
|
|
Assets/Liabilities
|
|
|
Inputs
|
|
|
Assets/Liabilities
|
|
|
Inputs
|
|
Description
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
1
|
|
|
Level
2
|
|
|
|
(In
thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of
commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
derivatives
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
7,191
|
|
Investment
securities
|
|
|
12,946
|
|
|
|
-
|
|
|
|
7,188
|
|
|
|
-
|
|
Total
assets
|
|
$
|
12,946
|
|
|
$
|
-
|
|
|
$
|
7,188
|
|
|
$
|
7,191
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of
derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives
|
|
$
|
-
|
|
|
$
|
194,701
|
|
|
$
|
-
|
|
|
$
|
55,885
|
|
Interest
derivatives
|
|
|
-
|
|
|
|
658
|
|
|
|
-
|
|
|
|
1,044
|
|
Total
liabilities
|
|
$
|
-
|
|
|
$
|
195,359
|
|
|
$
|
-
|
|
|
$
|
56,929
|
|
9.
Inventory
The
Company maintains an inventory of tubular goods and other well equipment for use
in its exploration and development drilling activities. Any gains or
losses on disposition of inventory, and any losses on write-down of inventory to
its estimated market value, are reported as gain or loss on sales of property
and equipment in the accompanying consolidated statements of
operations. The 2007 period included a charge of $8.9 million to
write-down inventory to its estimated market value at June 30,
2007. The write-down resulted primarily from the sale of certain
surplus equipment at an auction in March 2007. The Company received
$4.5 million of net proceeds from the auction in April 2007 when the
auction sale was consummated.
10.
Income Taxes
The
Company’s effective federal and state income tax rate for the six months ended
June 30, 2008 of 35.1% differed from the statutory federal rate of 35% due to
tax benefits derived from excess statutory depletion deductions, offset in part
by increases in the tax provision related primarily to the effects of the
recently-enacted Texas Margin Tax and certain non-deductible
expenses.
The
Company and its subsidiaries file federal income tax returns with the United
States Internal Revenue Service (“IRS”) and state income tax returns in various
state tax jurisdictions. The Company’s tax returns for fiscal years
after 2002 currently remain subject to examination by appropriate taxing
authorities. None of the Company’s income tax returns are under
examination at this time.
In June
2006, the FASB issued Interpretation No. 48, “
Accounting for Uncertainty in Income
Taxes”
(“FIN 48”). Upon adoption of FIN 48, the Company recorded a
liability for taxes payable related to unrecognized tax benefits arising from
uncertain tax positions taken by the Company in previous periods. A
reconciliation of the changes in this tax liability as of June 30, 2008 and
December 31, 2007 is as follows:
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Balance
at beginning of
period
|
|
$
|
358
|
|
|
$
|
-
|
|
Adoption of FIN 48 on January 1,
2007
|
|
|
-
|
|
|
|
1,585
|
|
Reductions for tax positions of
prior
years
|
|
|
-
|
|
|
|
(1,227
|
)
|
Balance
at end of
period
|
|
$
|
358
|
|
|
$
|
358
|
|
No
unrecognized tax benefits originated during the first six months of
2008. Reductions in the 2007 tax liability resulted from changes in
accounting methods which were submitted to the taxing authority during
2007. All of the remaining unrecognized tax benefits at June 30, 2008
relate to tax positions for which the ultimate deductibility is highly certain
but for which there is uncertainty about the timing of such
deductions. Because of the impact of deferred tax accounting, the
disallowance of the shorter deduction period would not affect the annual
effective tax rate but would only accelerate the payment of taxes to the taxing
authority or change the amount of deferred tax assets related to net operating
loss carryforwards.
Tax
liabilities recorded under FIN 48 are included in other non-current liabilities
in the accompanying consolidated financial statements, and any interest and
penalties accrued on unrecognized tax benefits, are recorded as interest expense
in the accompanying statements of operations. However, due to the
Company’s net operating loss carryforwards, no interest or penalties have been
accrued on the Company’s unrecognized tax benefits.
11.
Investments
Larclay
JV
In April
2006, the Company formed a joint venture (“Larclay JV”) with Lariat Services,
Inc. (“Lariat”) to construct, own and operate 12 new drilling
rigs. The Company and Lariat each own a 50% interest in Larclay
JV. A lender has provided a $75 million secured term loan to Larclay
JV to finance most of the cost of constructing and initially equipping the rigs
(see Note 4). The Company has made loans to Larclay JV totaling $8.6
million to finance excess construction costs and its 50% share of working
capital assessments made by Larclay JV. Loans to Larclay JV are due
on demand and bear interest, payable monthly, at the same rate as the secured
term loan. However, the loans are subject to a subordination
agreement with the secured lender that imposes restrictions on payments of
principal and interest on the loans.
Also in
April 2006, the Company entered into a three-year drilling contract with Larclay
JV assuring the availability of each rig for use in the ordinary course of the
Company’s exploration and development drilling program throughout the term of
the drilling contract. The provisions of the drilling contract
provide that the Company contract for each rig on a well-by-well basis at then
current market rates. If a rig is not needed by the Company at any
time during the term of the contract, Larclay JV may contract with other
operators for the use of such rig, subject to certain
restrictions. If a rig is idle, the Company will pay Larclay JV an
idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor
expenses, if applicable), depending on the size of the rig. The
Company’s maximum potential obligation to pay idle rig rates over the term of
this drilling contract, excluding any crew labor expenses, totals approximately
$59.2 million at June 30, 2008. The Company paid $489,000 for
idle rig fees during the six months ended June 30, 2008.
Although
the Company and Lariat own equal interests in Larclay JV, the Company meets the
definition of the primary beneficiary of Larclay JV’s expected cash flows under
FIN 46R. As the primary beneficiary under FIN 46R, the Company is
required to include the accounts of Larclay JV in the Company’s consolidated
financial statements. As of June 30, 2008, Lariat’s equity ownership
in the net assets of Larclay JV was $5.2 million, which is recorded as
minority interest and included in other non-current liabilities in the
accompanying consolidated financial statements. The Company’s
intercompany accounts and profits with Larclay JV have been eliminated in
consolidation.
SandRidge Energy
Inc.
The
Company owns 200,460 shares of common stock in SandRidge Energy Inc.
(“SandRidge”). During the fourth quarter of 2007, SandRidge became
publicly traded and listed its shares on the New York Stock
Exchange. The Company’s original cost investment in SandRidge was
increased to fair market value in 2007 and the change in fair market value of
$4.2 million, net of tax of $1.5 million, was recorded in accumulated other
comprehensive income at December 31, 2007. The fair value of the
Company’s investment in SandRidge at June 30, 2008 is $12.9 million and is
recorded in other non-current assets, based on the closing price of the stock as
of June 30, 2008. The change in fair market value during the six
months ended June 30, 2008 of $5.8 million, net of tax of $2 million, was
recorded in accumulated other comprehensive income.
12.
Oil and Gas Properties
The
following sets forth the capitalized costs for oil and gas properties as of June
30, 2008 and December 31, 2007.
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$
|
1,248,832
|
|
|
$
|
1,258,166
|
|
Unproved
properties
|
|
|
155,389
|
|
|
|
115,924
|
|
Total capitalized
costs
|
|
|
1,404,221
|
|
|
|
1,374,090
|
|
Accumulated depreciation,
depletion and amortization
|
|
|
(717,960
|
)
|
|
|
(727,739
|
)
|
Net capitalized
costs
|
|
$
|
686,261
|
|
|
$
|
646,351
|
|
13.
Sales of Property and Equipment
In April
2008, the Company and its affiliates sold all of their interests in 16 producing
wells for approximately $89.2 million, net of customary closing
adjustments. The Company recorded a gain of approximately $33.1
million in the second quarter of 2008 in connection with this
transaction. Also, in April 2008, the Company sold a surplus well
servicing unit for $1.8 million and recorded a gain of approximately $75,000 in
the second quarter of 2008 and also sold two 2,000 horsepower drilling rigs in
June 2008 for $21.8 million, net of customary closing adjustments and recorded a
gain of $5.7 million.
14.
Segment Information
In
accordance with SFAS No. 131 “
Disclosures about Segments of an
Enterprise and Related Information”
(“SFAS 131”), the Company has
two reportable operating segments, which are oil and gas exploration and
production and contract drilling services.
The
following tables present selected financial information regarding the Company’s
operating segments for the three-month and six-month periods ended June 30, 2008
and 2007.
For
the Three Months Ended
|
|
|
|
|
Contract
|
|
|
Intercompany
|
|
|
Consolidated
|
|
June
30, 2008
|
|
Oil
and Gas
|
|
|
Drilling
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In
thousands)
|
|
Revenues
|
|
$
|
178,076
|
|
|
$
|
16,874
|
|
|
$
|
(3,682
|
)
|
|
$
|
191,268
|
|
Depreciation,
depletion and amortization (a)
|
|
|
22,860
|
|
|
|
2,623
|
|
|
|
(509
|
)
|
|
|
24,974
|
|
Other
operating expenses (b)
|
|
|
37,235
|
|
|
|
12,753
|
|
|
|
(2,695
|
)
|
|
|
47,293
|
|
Interest
expense
|
|
|
5,136
|
|
|
|
941
|
|
|
|
-
|
|
|
|
6,077
|
|
Other
(income) expense
|
|
|
145,573
|
|
|
|
-
|
|
|
|
-
|
|
|
|
145,573
|
|
Income
(loss) before income taxes and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
minority
interest
|
|
|
(32,728
|
)
|
|
|
557
|
|
|
|
(478
|
)
|
|
|
(32,649
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax (expense) benefit
|
|
|
11,891
|
|
|
|
(249
|
)
|
|
|
-
|
|
|
|
11,642
|
|
Minority
interest, net of tax
|
|
|
87
|
|
|
|
(251
|
)
|
|
|
-
|
|
|
|
(164
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
(20,750
|
)
|
|
$
|
57
|
|
|
$
|
(478
|
)
|
|
$
|
(21,171
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$
|
826,711
|
|
|
$
|
95,304
|
|
|
$
|
(9,574
|
)
|
|
$
|
912,441
|
|
Additions
to property and equipment
|
|
$
|
93,395
|
|
|
$
|
608
|
|
|
$
|
(478
|
)
|
|
$
|
93,525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended
|
|
|
|
|
Contract
|
|
|
Intercompany
|
|
|
Consolidated
|
|
June
30, 2008
|
|
Oil
and Gas
|
|
|
Drilling
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In
thousands)
|
|
Revenues
|
|
$
|
300,102
|
|
|
$
|
34,037
|
|
|
$
|
(6,013
|
)
|
|
$
|
328,126
|
|
Depreciation,
depletion and amortization (a)
|
|
|
50,848
|
|
|
|
5,233
|
|
|
|
(834
|
)
|
|
|
55,247
|
|
Other
operating expenses (b)
|
|
|
68,050
|
|
|
|
25,761
|
|
|
|
(4,348
|
)
|
|
|
89,463
|
|
Interest
expense
|
|
|
11,488
|
|
|
|
2,035
|
|
|
|
-
|
|
|
|
13,523
|
|
Other
(income) expense
|
|
|
191,027
|
|
|
|
-
|
|
|
|
-
|
|
|
|
191,027
|
|
Income
(loss) before income taxes and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
minority
interest
|
|
|
(21,311
|
)
|
|
|
1,008
|
|
|
|
(831
|
)
|
|
|
(21,134
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax (expense) benefit
|
|
|
7,927
|
|
|
|
(507
|
)
|
|
|
-
|
|
|
|
7,420
|
|
Minority
interest, net of tax
|
|
|
149
|
|
|
|
(427
|
)
|
|
|
-
|
|
|
|
(278
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
(13,235
|
)
|
|
$
|
74
|
|
|
$
|
(831
|
)
|
|
$
|
(13,992
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$
|
826,711
|
|
|
$
|
95,304
|
|
|
$
|
(9,574
|
)
|
|
$
|
912,441
|
|
Additions
to property and equipment
|
|
$
|
148,826
|
|
|
$
|
617
|
|
|
$
|
(831
|
)
|
|
$
|
148,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended
|
|
|
|
|
Contract
|
|
|
Intercompany
|
|
|
Consolidated
|
|
June
30, 2007
|
|
Oil
and Gas
|
|
|
Drilling
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In
thousands)
|
|
Revenues
|
|
$
|
78,336
|
|
|
$
|
16,939
|
|
|
$
|
(2,711
|
)
|
|
$
|
92,564
|
|
Depreciation,
depletion and amortization (a)
|
|
|
17,104
|
|
|
|
2,172
|
|
|
|
(310
|
)
|
|
|
18,966
|
|
Other
operating expenses (b)
|
|
|
52,182
|
|
|
|
9,816
|
|
|
|
(2,098
|
)
|
|
|
59,900
|
|
Interest
expense
|
|
|
6,939
|
|
|
|
1,047
|
|
|
|
-
|
|
|
|
7,986
|
|
Other
(income) expense
|
|
|
(9,724
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(9,724
|
)
|
Income
(loss) before income taxes and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
minority
interest
|
|
|
11,835
|
|
|
|
3,904
|
|
|
|
(303
|
)
|
|
|
15,436
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax (expense) benefit
|
|
|
(3,991
|
)
|
|
|
(1,366
|
)
|
|
|
-
|
|
|
|
(5,357
|
)
|
Minority
interest, net of tax
|
|
|
-
|
|
|
|
(1,269
|
)
|
|
|
-
|
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
7,844
|
|
|
$
|
1,269
|
|
|
$
|
(303
|
)
|
|
$
|
8,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$
|
746,953
|
|
|
$
|
97,866
|
|
|
$
|
(3,389
|
)
|
|
$
|
841,430
|
|
Additions
to property and equipment
|
|
$
|
59,097
|
|
|
$
|
4,066
|
|
|
$
|
(303
|
)
|
|
$
|
62,860
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended
|
|
|
|
|
Contract
|
|
|
Intercompany
|
|
|
Consolidated
|
|
June
30, 2007
|
|
Oil
and Gas
|
|
|
Drilling
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In
thousands)
|
|
Revenues
|
|
$
|
142,420
|
|
|
$
|
27,875
|
|
|
$
|
(5,230
|
)
|
|
$
|
165,065
|
|
Depreciation,
depletion and amortization (a)
|
|
|
31,517
|
|
|
|
3,779
|
|
|
|
(534
|
)
|
|
|
34,762
|
|
Other
operating expenses (b)
|
|
|
98,628
|
|
|
|
15,643
|
|
|
|
(3,908
|
)
|
|
|
110,363
|
|
Interest
expense
|
|
|
13,734
|
|
|
|
1,881
|
|
|
|
-
|
|
|
|
15,615
|
|
Other
(income) expense
|
|
|
6,412
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6,412
|
|
Income
(loss) before income taxes and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
minority
interest
|
|
|
(7,871
|
)
|
|
|
6,572
|
|
|
|
(788
|
)
|
|
|
(2,087
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax (expense) benefit
|
|
|
3,023
|
|
|
|
(2,300
|
)
|
|
|
-
|
|
|
|
723
|
|
Minority
interest, net of tax
|
|
|
-
|
|
|
|
(2,136
|
)
|
|
|
-
|
|
|
|
(2,136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
(4,848
|
)
|
|
$
|
2,136
|
|
|
$
|
(788
|
)
|
|
$
|
(3,500
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$
|
746,953
|
|
|
$
|
97,866
|
|
|
$
|
(3,389
|
)
|
|
$
|
841,430
|
|
Additions
to property and equipment
|
|
$
|
120,621
|
|
|
$
|
20,135
|
|
|
$
|
(788
|
)
|
|
$
|
139,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Includes impairment
of property and equipment.
|
|
(b)
Includes the
following expenses: production, exploration, natural gas services,
drilling rig services, accretion of abandonment obligations, general and
administrative and loss on sales of property and
equipment.
|
|
15.
Guarantor Financial Information
In July
2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of
Senior Notes (see Note 4). Other than West Coast Energy
Properties GP, LLC (“WCEP LLC”), the general partner of West Coast Energy
Properties, L.P., an affiliated limited partnership, all of the Issuer’s
wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and
severally, irrevocably and unconditionally guaranteed the performance and
payment when due of all obligations under the Senior Notes. Larclay
JV, a 50%-owned drilling rig joint venture formed in April 2006, and WCEP LLC
have not guaranteed the Senior Notes and are referred to in this Note 15 as
Non-Guarantor Entities.
The
financial information which follows sets forth the Company’s condensed
consolidating financial statements as of and for the periods
indicated.
Condensed
Consolidating Balance Sheet
June
30, 2008
(Unaudited)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
(Dollars
in thousands)
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Current
assets
|
|
$
|
127,770
|
|
|
$
|
116,405
|
|
|
$
|
20,853
|
|
|
$
|
(140,505
|
)
|
|
$
|
124,523
|
|
Property
and equipment, net
|
|
|
378,977
|
|
|
|
305,810
|
|
|
|
81,477
|
|
|
|
-
|
|
|
|
766,264
|
|
Investments
in subsidiaries
|
|
|
86,533
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(86,533
|
)
|
|
|
-
|
|
Other
assets
|
|
|
29,645
|
|
|
|
353
|
|
|
|
256
|
|
|
|
(8,600
|
)
|
|
|
21,654
|
|
Total
assets
|
|
$
|
622,925
|
|
|
$
|
422,568
|
|
|
$
|
102,586
|
|
|
$
|
(235,638
|
)
|
|
$
|
912,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
241,652
|
|
|
$
|
176,451
|
|
|
$
|
37,509
|
|
|
$
|
(140,505
|
)
|
|
$
|
315,107
|
|
Non-current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
275,000
|
|
|
|
-
|
|
|
|
42,600
|
|
|
|
(8,600
|
)
|
|
|
309,000
|
|
Fair
value of derivatives
|
|
|
47,853
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
47,853
|
|
Other
|
|
|
17,431
|
|
|
|
56,411
|
|
|
|
106
|
|
|
|
-
|
|
|
|
73,948
|
|
|
|
|
340,284
|
|
|
|
56,411
|
|
|
|
42,706
|
|
|
|
(8,600
|
)
|
|
|
430,801
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity
|
|
|
40,989
|
|
|
|
189,706
|
|
|
|
22,371
|
|
|
|
(86,533
|
)
|
|
|
166,533
|
|
Total
liabilities and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stockholders’
equity
|
|
$
|
622,925
|
|
|
$
|
422,568
|
|
|
$
|
102,586
|
|
|
$
|
(235,638
|
)
|
|
$
|
912,441
|
|
Condensed
Consolidating Balance Sheet
December
31, 2007
(Dollars
in thousands)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Current
assets
|
|
$
|
127,668
|
|
|
$
|
109,010
|
|
|
$
|
21,225
|
|
|
$
|
(145,524
|
)
|
|
$
|
112,379
|
|
Property
and equipment, net
|
|
|
369,421
|
|
|
|
275,609
|
|
|
|
86,048
|
|
|
|
-
|
|
|
|
731,078
|
|
Investments
in subsidiaries
|
|
|
81,583
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(81,583
|
)
|
|
|
-
|
|
Other
assets
|
|
|
21,354
|
|
|
|
340
|
|
|
|
545
|
|
|
|
(4,600
|
)
|
|
|
17,639
|
|
Total
assets
|
|
$
|
600,026
|
|
|
$
|
384,959
|
|
|
$
|
107,818
|
|
|
$
|
(231,707
|
)
|
|
$
|
861,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
112,536
|
|
|
$
|
179,243
|
|
|
$
|
42,512
|
|
|
$
|
(145,524
|
)
|
|
$
|
188,767
|
|
Non-current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
390,800
|
|
|
|
-
|
|
|
|
43,975
|
|
|
|
(4,600
|
)
|
|
|
430,175
|
|
Other
|
|
|
24,708
|
|
|
|
56,528
|
|
|
|
112
|
|
|
|
-
|
|
|
|
81,348
|
|
|
|
|
415,508
|
|
|
|
56,528
|
|
|
|
44,087
|
|
|
|
(4,600
|
)
|
|
|
511,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity
|
|
|
71,982
|
|
|
|
149,188
|
|
|
|
21,219
|
|
|
|
(81,583
|
)
|
|
|
160,806
|
|
Total
liabilities and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stockholders’
equity
|
|
$
|
600,026
|
|
|
$
|
384,959
|
|
|
$
|
107,818
|
|
|
$
|
(231,707
|
)
|
|
$
|
861,096
|
|
Condensed
Consolidating Statement of Operations
Three
Months Ended June 30, 2008
(Unaudited)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
(Dollars
in thousands)
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Total
revenue
|
|
$
|
127,281
|
|
|
$
|
51,269
|
|
|
$
|
17,217
|
|
|
$
|
(4,499
|
)
|
|
$
|
191,268
|
|
Costs
and
expenses
|
|
|
39,800
|
|
|
|
20,972
|
|
|
|
15,516
|
|
|
|
(4,021
|
)
|
|
|
72,267
|
|
Operating
income (loss)
|
|
|
87,481
|
|
|
|
30,297
|
|
|
|
1,701
|
|
|
|
(478
|
)
|
|
|
119,001
|
|
Other
income (expense)
|
|
|
(141,834
|
)
|
|
|
(8,912
|
)
|
|
|
(904
|
)
|
|
|
-
|
|
|
|
(151,650
|
)
|
Income
tax
benefit
|
|
|
11,642
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,642
|
|
Minority
interest, net of tax
|
|
|
(164
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(164
|
)
|
Net
income
(loss)
|
|
$
|
(42,875
|
)
|
|
$
|
21,385
|
|
|
$
|
797
|
|
|
$
|
(478
|
)
|
|
$
|
(21,171
|
)
|
Condensed
Consolidating Statement of Operations
Six
Months Ended June 30, 2008
(Unaudited)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
(Dollars
in thousands)
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Total
revenue
|
|
$
|
207,513
|
|
|
$
|
93,242
|
|
|
$
|
34,580
|
|
|
$
|
(7,209
|
)
|
|
$
|
328,126
|
|
Costs
and
expenses
|
|
|
79,671
|
|
|
|
40,100
|
|
|
|
31,317
|
|
|
|
(6,378
|
)
|
|
|
144,710
|
|
Operating
income (loss)
|
|
|
127,842
|
|
|
|
53,142
|
|
|
|
3,263
|
|
|
|
(831
|
)
|
|
|
183,416
|
|
Other
income (expense)
|
|
|
(190,103
|
)
|
|
|
(12,490
|
)
|
|
|
(1,957
|
)
|
|
|
-
|
|
|
|
(204,550
|
)
|
Income
tax
benefit
|
|
|
7,420
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7,420
|
|
Minority
interest, net of tax
|
|
|
(278
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(278
|
)
|
Net
income
(loss)
|
|
$
|
(55,119
|
)
|
|
$
|
40,652
|
|
|
$
|
1,306
|
|
|
$
|
(831
|
)
|
|
$
|
(13,992
|
)
|
Condensed
Consolidating Statement of Operations
Three
Months Ended June 30, 2007
(Unaudited)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
(Dollars
in thousands)
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Total
revenue
|
|
$
|
52,272
|
|
|
$
|
26,311
|
|
|
$
|
17,098
|
|
|
$
|
(3,117
|
)
|
|
$
|
92,564
|
|
Costs
and
expenses
|
|
|
53,357
|
|
|
|
16,195
|
|
|
|
12,128
|
|
|
|
(2,814
|
)
|
|
|
78,866
|
|
Operating
income (loss)
|
|
|
(1,085
|
)
|
|
|
10,116
|
|
|
|
4,970
|
|
|
|
(303
|
)
|
|
|
13,698
|
|
Other
income (expense)
|
|
|
1,557
|
|
|
|
1,204
|
|
|
|
(1,023
|
)
|
|
|
-
|
|
|
|
1,738
|
|
Income
tax
expense
|
|
|
(5,357
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(5,357
|
)
|
Minority
interest, net of tax
|
|
|
(1,269
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,269
|
)
|
Net
income
(loss)
|
|
$
|
(6,154
|
)
|
|
$
|
11,320
|
|
|
$
|
3,947
|
|
|
$
|
(303
|
)
|
|
$
|
8,810
|
|
Condensed
Consolidating Statement of Operations
Six
Months Ended June 30, 2007
(Unaudited)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
(Dollars
in thousands)
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Total
revenue
|
|
$
|
92,399
|
|
|
$
|
50,480
|
|
|
$
|
28,136
|
|
|
$
|
(5,950
|
)
|
|
$
|
165,065
|
|
Costs
and
expenses
|
|
|
98,250
|
|
|
|
32,334
|
|
|
|
19,703
|
|
|
|
(5,162
|
)
|
|
|
145,125
|
|
Operating
income (loss)
|
|
|
(5,851
|
)
|
|
|
18,146
|
|
|
|
8,433
|
|
|
|
(788
|
)
|
|
|
19,940
|
|
Other
income (expense)
|
|
|
(18,000
|
)
|
|
|
(2,198
|
)
|
|
|
(1,829
|
)
|
|
|
-
|
|
|
|
(22,027
|
)
|
Income
tax
benefit
|
|
|
723
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
723
|
|
Minority
interest, net of tax
|
|
|
(2,136
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,136
|
)
|
Net
income
(loss)
|
|
$
|
(25,264
|
)
|
|
$
|
15,948
|
|
|
$
|
6,604
|
|
|
$
|
(788
|
)
|
|
$
|
(3,500
|
)
|
Condensed
Consolidating Statement of Cash Flows
Six
Months Ended June 30, 2008
(Unaudited)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
(Dollars
in thousands)
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Operating
activities
|
|
$
|
72,828
|
|
|
$
|
72,085
|
|
|
$
|
3,675
|
|
|
$
|
833
|
|
|
$
|
149,421
|
|
Investing
activities
|
|
|
37,709
|
|
|
|
(46,480
|
)
|
|
|
(839
|
)
|
|
|
(833
|
)
|
|
|
(10,443
|
)
|
Financing
activities
|
|
|
(103,553
|
)
|
|
|
(25,166
|
)
|
|
|
(5,111
|
)
|
|
|
-
|
|
|
|
(133,830
|
)
|
Net
increase (decrease) in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
and cash equivalents
|
|
|
6,984
|
|
|
|
439
|
|
|
|
(2,275
|
)
|
|
|
-
|
|
|
|
5,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
at the beginning of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
the
period
|
|
|
5,325
|
|
|
|
1,288
|
|
|
|
5,731
|
|
|
|
-
|
|
|
|
12,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
at end of the period
|
|
$
|
12,309
|
|
|
$
|
1,727
|
|
|
$
|
3,456
|
|
|
$
|
-
|
|
|
$
|
17,492
|
|
Condensed
Consolidating Statement of Cash Flows
Six
Months Ended June 30, 2007
(Unaudited)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
(Dollars
in thousands)
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Operating
activities
|
|
$
|
58,415
|
|
|
$
|
21,692
|
|
|
$
|
9,295
|
|
|
$
|
534
|
|
|
$
|
89,936
|
|
Investing
activities
|
|
|
(110,585
|
)
|
|
|
(7,652
|
)
|
|
|
(20,411
|
)
|
|
|
(34
|
)
|
|
|
(138,682
|
)
|
Financing
activities
|
|
|
49,095
|
|
|
|
(14,124
|
)
|
|
|
8,721
|
|
|
|
(500
|
)
|
|
|
43,192
|
|
Net
increase (decrease) in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
and cash equivalents
|
|
|
(3,075
|
)
|
|
|
(84
|
)
|
|
|
(2,395
|
)
|
|
|
-
|
|
|
|
(5,554
|
)
|
Cash
at the beginning of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
the
period
|
|
|
6,116
|
|
|
|
1,298
|
|
|
|
6,426
|
|
|
|
-
|
|
|
|
13,840
|
|
Cash
at end of the period
|
|
$
|
3,041
|
|
|
$
|
1,214
|
|
|
$
|
4,031
|
|
|
$
|
-
|
|
|
$
|
8,286
|
|
Item 2
-
Management's
Discussion
and Analysis of Financial Condition and Results of
Operations
The
following discussion is intended to provide information relevant to an
understanding of our financial condition, changes in our financial condition and
our results of operations and cash flows and should be read in conjunction with
our consolidated financial statements and notes thereto included elsewhere in
this Form 10-Q and in our Form 10-K for the year ended December 31,
2007.
Forward-Looking
Statements
Certain
information included in this quarterly report contains forward-looking
statements that are based on management’s current
expectations. Forward-looking statements include statements regarding
our plans, beliefs or current expectations and may be signified by the words
“could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”,
“intend”, “budget”, “plan”, “forecast”, “predict” and other similar
expressions. Forward-looking statements appear throughout this Form
10-Q with respect to, among other things: profitability; planned capital
expenditures; estimates of oil and gas production; future project dates;
estimates of future oil and gas prices; estimates of oil and gas reserves; our
future financial condition or results of operations; and our business strategy
and other plans and objectives for future operations. Actual results
in future periods may differ materially from those expressed or implied by such
forward-looking statements because of a number of risks and uncertainties
affecting our business, including those discussed in “Item 1 – Business – Risk
Factors” included in our Form 10-K for the year ended December 31,
2007. We disclaim any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
Overview
We are an
independent oil and natural gas exploration, development, acquisition, and
production company. Our basic business model is to increase
shareholder value by finding and developing oil and gas reserves through
exploration and development activities, and selling the production from those
reserves at a profit. To be successful, we must, over time, be able
to find oil and gas reserves and then sell the resulting production at a price
that is sufficient to cover our finding costs, operating expenses,
administrative costs and interest expense, plus offer us a return on our capital
investment. From time to time, we may also acquire producing
properties if we believe the acquired assets offer us the potential for reserve
growth through additional developmental or exploratory drilling
activities.
We
believe that the economic climate in the domestic oil and gas industry continues
to be suitable for our business model. Oil and gas prices are
currently well above historic averages. Although oil and gas prices
are typically volatile and are subject to market fluctuations, we believe that
supply and demand fundamentals in the energy marketplace continue to provide us
with the economic incentives necessary for us to assume the risks we face in our
search for oil and gas reserves. However, despite favorable commodity
prices, certain of our operating metrics per Mcfe, such as finding costs and
depreciation, depletion and amortization (“DD&A”) expense, are
rising.
Finding
quality domestic oil and gas reserves through exploration is a significant
challenge and involves a high degree of risk. DD&A per Mcfe of
oil and gas production, an operating metric that measures a company’s cumulative
cost to find or purchase a unit of production, increased significantly from the
first six months of 2007 to the first six months of
2008. Approximately 73% of our planned activities for 2008 relate to
developmental prospects that are not expected to materially reduce our reported
DD&A per Mcfe.
Key
Factors to Consider
The
following summarizes the key factors considered by management in the review of
our financial condition and operating performance for the second quarter of 2008
and the outlook for the remainder of 2008.
·
|
Our
oil and gas sales for the second quarter increased $59.4 million, or 79%,
from 2007. Price variances accounted for 98% of this increase,
and incremental production accounted for the remaining
2%.
|
·
|
We
recorded a net gain on the sale of property and equipment of $40.4 million
during the second quarter of 2008. We sold all of our interests
in 16 producing wells in South Louisiana resulting in a gain of
approximately $33.1 million. We also sold two drillings and a
surplus well servicing unit for a net gain of approximately $5.7 million
in the second quarter of 2008.
|
|
Our
oil and gas production for the second quarter of 2008 was 4% lower on an
Mcfe basis than in the comparable period in 2007. Our oil
production was 22% higher than the second quarter of 2007 and gas
production was 19% lower compared to the 2007 period. The
growth in oil production was attributed to in-fill drilling in the Austin
Chalk (Trend) and increased drilling activities in the Permian
Basin. As adjusted for the South Louisiana asset sale, gas
production was favorably impacted by incremental production from drilling
activities in North Louisiana.
|
·
|
We
recorded a $148.6 million net loss on derivatives in the second
quarter of 2008. We recorded a $35 million realized loss
on settled contracts and a $113.6 million loss for changes in
mark-to-market valuations. Since we do not presently designate
our derivatives as cash flow hedges under applicable accounting standards,
we recognize the full effect of changing prices on mark-to-market
valuations as a current charge or credit to our results of
operations.
|
·
|
During
2008, we decreased borrowings under our revolving credit facility by
$115.8 million from $165.8 million at December 31, 2007 to $50
million at June 30, 2008 due primarily from proceeds from the sale of
assets.
|
·
|
At
June 30, 2008, our capitalized unproved oil and gas properties totaled
$155.4 million, of which approximately $86.1 million was attributable
to unproved acreage. Unproved properties are subject to a
valuation impairment to the extent the carrying cost of a prospect exceeds
its estimated fair value. Therefore, our results of operations
in future periods may be adversely affected by unproved property
impairments.
|
Recent
Exploration and Developmental Activities
Overview
Most of
our exploration and development efforts in 2008 are directed toward
developmental drilling for oil. With oil prices at current levels, we
believe the time is right to exploit our large inventory of lower risk,
developmental drilling locations, primarily in the Permian Basin and the Austin
Chalk (Trend) areas of our asset base. However, we remain committed
to our higher risk, higher impact exploration programs, particularly our deep
Bossier plays in East Texas and North Louisiana.
As
discussed in “Liquidity and Capital Resources – Capital Expenditures,” we
incurred expenditures for exploration and development activities of $154.7
million during the first six months of 2008, of which approximately 19% were
related to exploratory drilling and leasing activities. We also
increased our estimates for capital expenditures in fiscal 2008 from $344.5
million to $400.7 million. The increase in capital spending
relates primarily to planned developmental drilling activities in the Permian
Basin and North Louisiana and exploratory drilling activities in South
Louisiana.
Permian
Basin
The
Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico
known for its large oil and gas deposits from the Permian geologic
period. Although many fields in the Permian Basin have been heavily
exploited in the past, higher product prices and improved technology (including
deep horizontal drilling) continue to encourage high levels of current drilling
and recompletion activities. We gained a significant position in the
Permian Basin in 2004 when we acquired Southwest Royalties, Inc. This
acquisition provided us with an inventory of potential drilling and recompletion
activities that we are beginning to exploit.
We spent
$60.4 million in the Permian Basin during the first half of 2008 on
exploration and development activities, of which $54 million was spent on
drilling and completion activities and $6.4 million was spent on seismic and
leasing activities. We drilled 18 gross (16.3 net) operated
wells in the Permian Basin and conducted various remedial operations on other
wells in the first half of 2008.
The
Permian Basin continues to be a significant source of cash flow for
us. We currently expect to spend $123.7 million on developmental
drilling activities in the Permian Basin during the last half of
2008. Most of the planned drilling activities in the Permian Basin
relate to our War-Wink, Amacker-Tippett Andrews County, and Barstow areas of
West Texas. In the War-Wink area, we are presently drilling
horizontal wells targeting oil-prone sands in the Bone Spring
formation. In the Amacker-Tippett, Andrews County and Barstow areas,
our planned drilling activities relate primarily to wells targeting oil-prone
sands in the Spraberry and Wolfcamp formations.
Austin
Chalk (Trend)
Prior to
1998, we concentrated our drilling activities in an oil-prone area we refer to
as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Milam and Leon
Counties, Texas. Most of our wells in this area were drilled as horizontal
wells, many with multiple laterals in different producing horizons, including
the Austin Chalk, Buda and Georgetown formations. The existing
spacing between some of our wells in this area affords us the opportunity to tap
additional oil and gas reserves by drilling new wells between existing wells, a
technique referred to as in-fill drilling. These in-fill wells are
considered lower risk as compared to exploratory wells and, with oil prices at
current levels, we believe that the rates of return are now
attractive. In addition, we are conducting secondary water frac
operations on existing wells in the Austin Chalk (Trend) area to improve
production rates and add new reserves. We spent $28.6 million in the
Austin Chalk (Trend) area during the first half of 2008 and currently plan to
spend an additional $28.9 million primarily on developmental drilling and
recompletion activities during the last half of 2008.
North
Louisiana
In 2005,
we began a drilling program in North Louisiana targeting the Cotton Valley/Gray
and Bossier formations. In this area, the Cotton Valley/Gray
formations are encountered at depths ranging from 8,000 to 12,000 feet, and
the Bossier formation is encountered at depths ranging from 11,000 to
15,500 feet. We believe that these tight sandstone formations
have become more economically viable due to higher product prices, coupled with
enhanced drilling and completion techniques. We currently have
approximately 170,000 net acres leased for Bossier drilling in North
Louisiana.
We spent
$34.6 million in North Louisiana during the first half of 2008 on
exploration and development activities, of which $32.6 million was spent on
drilling and completion activities and $2 million was spent on seismic and
leasing activities. We currently plan to spend an additional $48.8
million in North Louisiana during the last half of 2008.
To date,
we have drilled 16 wells on our Terryville prospect and have completed 14 as
producers, with one well waiting on completion activities to
commence. We plan to drill two additional development wells on this
prospect during the remainder of 2008. On our Ruston prospect, we
have completed two wells as producers and are currently drilling a third
well. We plan to drill two additional wells on this prospect during
the remainder of 2008.
In 2007,
adverse drilling conditions forced us to abandon the David Barton #1, an
exploratory well in the Winnsboro prospect in Richland Parish, prior to reaching
the pressured Bossier formation. We are currently drilling an offset
to this well.
South
Louisiana
Prior to
2008, we had drilled 75 gross (60.3 net) exploratory wells in South Louisiana,
of which 39 gross (30 net) were completed as producers.
We spent
$17 million in South Louisiana during the first half of 2008 on exploration and
development activities, of which $15.2 million was spent on drilling and
completion activities and $1.8 was spent on seismic and leasing
activities. We have completed two development wells on our Fleur
prospect in Plaquemines Parish and plan to drill another well during the
remainder of 2008.
In late
2007, we entered into an agreement with an industry partner, under which they
have committed to drill five wells on certain of our prospects in South
Louisiana during 2008. The industry partner will operate the wells, and we will
have a 15% before casing point working interest and a 50% after casing point
working interest in each well drilled. To date, three wells have
been completed and are awaiting production facilities, and two additional wells
are planned for the last half of 2008.
In April
2008, we sold all of our interests in 16 producing wells in South Louisiana to
an industry partner for approximately $89.2 million, net of customary closing
adjustments, and recorded a gain of $33.1 million in the second quarter of 2008
in connection with this transaction.
We
currently plan to spend an additional $18.7 million in South Louisiana
during the last half of 2008 primarily to participate in drilling an exploratory
well in Plaquemines Parish on our West Lake Washington prospect and to drill a
development well on our Fleur prospect.
East
Texas Bossier
We
currently have approximately 145,000 net acres under lease in East Texas
targeting the prolific deep Bossier sands which are encountered at depths
ranging from 14,000 to 22,000 feet in this area. Of this
acreage, approximately 70,000 net acres are held by production from existing
Austin Chalk (Trend) wells. Exploration for deep Bossier gas sands in
this area is in its early stages and involves a high degree of
risk. The geological structures are complex, and limited drilling
activity offers minimal subsurface control. Deep Bossier wells are
expensive to drill, with completed wells costing approximately $18 million
each. Although seismic data is helpful in identifying possible sand
accumulations, the only way to determine if the deep Bossier sand will be
commercially productive is to drill wells to the targeted
structures.
Late in
2007, we drilled two wells in this area targeting the deep Bossier, the Big Bill
Simpson #1, a 19,000-foot exploratory well in Leon County (70% working
interest), and the Margarita #1, a 20,000-foot exploratory well in Robertson
County (100% working interest). The Big Bill Simpson well encountered
a thick section of lower and middle Bossier sands, but these sands had limited
porosity. The Margarita #1 well only encountered the upper Bossier
sand. We are currently evaluating these wells to determine if they
are capable of producing at commercial quantities. If we are unable
to establish sufficient production levels from either of these two wells,
results of operations in subsequent quarters may be adversely affected by the
write-off or impairment of those wells.
We spent
$11.8 million in the East Texas Bossier area during the first half of 2008 and
currently plan to spend approximately $18.5 million during the remainder of the
year for leasing and seismic activities. Although the results of the Big Bill
Simpson #1 and the Margarita #1 to date have not met our expectations, we are
optimistic that our acreage position in this area is prospective for potentially
significant deep Bossier discoveries. As more wells are drilled and
more subsurface control data is obtained, we believe our prospects for
discoveries improve. We have begun a 3-D seismic shoot in Leon
County, Texas over the Big Bill Simpson prospect in an attempt to more clearly
define the location of our next well on this acreage. In addition, we
are conducting a proprietary 3-D shoot in Burleson County, Texas to help
identify other potential drill sites for deep Bossier tests in this
area.
Other
In Utah,
we plan to participate in the drilling of a 12,000-foot exploratory well, the
Lamb #1 in the Overthrust prospect (33% working interest) in Sanpete County,
Utah. The well will target the oil-prone Navajo sandstone
formation.
Supplemental
Information
The
following unaudited information is intended to supplement the consolidated
financial statements included in this Form 10-Q with data that is not readily
available from those statements.
|
|
Three
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
Oil
and Gas Production Data:
|
|
|
|
|
|
|
Gas
(MMcf)
|
|
|
4,177
|
|
|
|
5,151
|
|
Oil
(MBbls)
|
|
|
703
|
|
|
|
577
|
|
Natural gas liquids
(MBbls)
|
|
|
41
|
|
|
|
57
|
|
Total
(MMcfe)
|
|
|
8,641
|
|
|
|
8,955
|
|
|
|
|
|
|
|
|
|
|
Average
Realized Prices
(a)
:
|
|
|
|
|
|
|
|
|
Gas
($/Mcf)
|
|
$
|
11.07
|
|
|
$
|
7.20
|
|
Oil
($/Bbl)
|
|
$
|
121.51
|
|
|
$
|
62.51
|
|
Natural gas liquids
($/Bbl)
|
|
$
|
63.63
|
|
|
$
|
42.84
|
|
|
|
|
|
|
|
|
|
|
Gain
(Losses) on Settled Derivative Contracts
(a)
:
|
|
|
|
|
|
|
|
|
($ in thousands, except per
unit)
|
|
|
|
|
|
|
|
|
Gas: Net realized gain
(loss)
|
|
$
|
(10,287
|
)
|
|
$
|
473
|
|
Per unit produced
($/Mcf)
|
|
$
|
(2.46
|
)
|
|
$
|
.09
|
|
Oil: Net
realized loss
|
|
$
|
(23,348
|
)
|
|
$
|
(1,971
|
)
|
Per unit produced
($/Bbl)
|
|
$
|
(33.21
|
)
|
|
$
|
(3.42
|
)
|
|
|
|
|
|
|
|
|
|
Average
Daily Production:
|
|
|
|
|
|
|
|
|
Natural Gas
(Mcf):
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
|
14,284
|
|
|
|
13,724
|
|
North
Louisiana
|
|
|
15,233
|
|
|
|
5,229
|
|
South
Louisiana
|
|
|
7,347
|
|
|
|
27,206
|
|
Austin Chalk
(Trend)
|
|
|
2,133
|
|
|
|
2,445
|
|
Cotton Valley Reef
Complex
|
|
|
6,277
|
|
|
|
7,651
|
|
Other
|
|
|
627
|
|
|
|
349
|
|
Total
|
|
|
45,901
|
|
|
|
56,604
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls):
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
|
3,568
|
|
|
|
3,135
|
|
North
Louisiana
|
|
|
386
|
|
|
|
153
|
|
South
Louisiana
|
|
|
105
|
|
|
|
1,333
|
|
Austin Chalk
(Trend)
|
|
|
3,575
|
|
|
|
1,627
|
|
Other
|
|
|
91
|
|
|
|
93
|
|
Total
|
|
|
7,725
|
|
|
|
6,341
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
(Bbls):
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
|
153
|
|
|
|
226
|
|
Austin Chalk
(Trend)
|
|
|
241
|
|
|
|
251
|
|
Other
|
|
|
57
|
|
|
|
149
|
|
Total
|
|
|
451
|
|
|
|
626
|
|
(Continued)
|
|
Three
Months Ended
|
|
|
June
30,
|
|
|
2008
|
|
|
2007
|
Exploration
Costs (in thousands):
|
|
|
|
|
|
Abandonment and impairment
costs:
|
|
|
|
|
|
North
Louisiana
|
|
$
|
1,865
|
|
|
$
|
8,679
|
|
South
Louisiana
|
|
|
-
|
|
|
|
14,217
|
|
Other
|
|
|
68
|
|
|
|
623
|
|
Total
|
|
|
1,933
|
|
|
|
23,519
|
|
|
|
|
|
|
|
|
|
|
|
Seismic and
other
|
|
|
1,562
|
|
|
|
1,580
|
|
Total exploration
costs
|
|
$
|
3,495
|
|
|
$
|
25,099
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
Depletion and Amortization (in thousands):
|
|
|
|
|
|
|
|
|
|
Oil and gas
depletion
|
|
$
|
22,598
|
|
|
$
|
16,331
|
|
|
Contract drilling
depreciation
|
|
|
2,115
|
|
|
|
1,862
|
|
|
Other
depreciation
|
|
|
261
|
|
|
|
294
|
|
|
Total
DD&A
|
|
$
|
24,974
|
|
|
$
|
18,487
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and Gas Costs ($/Mcfe Produced):
|
|
|
|
|
|
|
|
|
|
Production
costs
|
|
$
|
2.54
|
|
|
$
|
1.99
|
|
|
Oil and gas
depletion
|
|
$
|
2.62
|
|
|
$
|
1.82
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Wells Drilled
(b)
:
|
|
|
|
|
|
|
|
|
|
Exploratory
Wells
|
|
|
1.0
|
|
|
|
4.2
|
|
|
Developmental
Wells
|
|
|
22.7
|
|
|
|
5.7
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
Oil
and Gas Production Data:
|
|
|
|
|
|
|
Gas
(MMcf)
|
|
|
9,725
|
|
|
|
9,478
|
|
Oil
(MBbls)
|
|
|
1,387
|
|
|
|
1,120
|
|
Natural gas liquids
(MBbls)
|
|
|
99
|
|
|
|
103
|
|
Total
(MMcfe)
|
|
|
18,641
|
|
|
|
16,816
|
|
|
|
|
|
|
|
|
|
|
Average
Realized Prices
(a)
:
|
|
|
|
|
|
|
|
|
Gas
($/Mcf)
|
|
$
|
9.81
|
|
|
$
|
7.06
|
|
Oil
($/Bbl)
|
|
$
|
109.05
|
|
|
$
|
58.95
|
|
Natural gas liquids
($/Bbl)
|
|
$
|
58.47
|
|
|
$
|
38.58
|
|
|
|
|
|
|
|
|
|
|
Gain
(Losses) on Settled Derivative Contracts
(a)
:
|
|
|
|
|
|
|
|
|
($ in thousands, except per
unit)
|
|
|
|
|
|
|
|
|
Gas: Net realized gain
(loss)
|
|
$
|
(11,171
|
)
|
|
$
|
4,982
|
|
Per unit produced
($/Mcf)
|
|
$
|
(1.15
|
)
|
|
$
|
.53
|
|
Oil: Net
realized loss
|
|
$
|
(36,254
|
)
|
|
$
|
(4,530
|
)
|
Per unit produced
($/Bbl)
|
|
$
|
(26.14
|
)
|
|
$
|
(4.04
|
)
|
(Continued)
|
|
Six
Months Ended
|
|
|
June
30,
|
|
|
2008
|
|
|
2007
|
Average
Daily Production:
|
|
|
|
|
|
Natural Gas
(Mcf):
|
|
|
|
|
|
Permian
Basin
|
|
|
14,665
|
|
|
|
14,552
|
|
North
Louisiana
|
|
|
14,611
|
|
|
|
3,815
|
|
South
Louisiana
|
|
|
15,405
|
|
|
|
23,695
|
|
Austin Chalk
(Trend)
|
|
|
2,333
|
|
|
|
2,228
|
|
Cotton Valley Reef
Complex
|
|
|
5,857
|
|
|
|
7,674
|
|
Other
|
|
|
563
|
|
|
|
401
|
|
Total
|
|
|
53,434
|
|
|
|
52,365
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls):
|
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
|
3,532
|
|
|
|
3,117
|
|
North
Louisiana
|
|
|
365
|
|
|
|
91
|
|
South
Louisiana
|
|
|
545
|
|
|
|
1,256
|
|
Austin Chalk
(Trend)
|
|
|
3,104
|
|
|
|
1,647
|
|
Other
|
|
|
75
|
|
|
|
77
|
|
Total
|
|
|
7,621
|
|
|
|
6,188
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
(Bbls):
|
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
|
185
|
|
|
|
211
|
|
Austin Chalk
(Trend)
|
|
|
258
|
|
|
|
259
|
|
Other
|
|
|
101
|
|
|
|
99
|
|
Total
|
|
|
544
|
|
|
|
569
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
Costs (in thousands):
|
|
|
|
|
|
|
|
|
|
Abandonment and impairment
costs:
|
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
$
|
-
|
|
|
$
|
989
|
|
North
Louisiana
|
|
|
2,162
|
|
|
|
8,985
|
|
South
Louisiana
|
|
|
-
|
|
|
|
21,396
|
|
Other
|
|
|
68
|
|
|
|
3,254
|
|
Total
|
|
|
2,230
|
|
|
|
34,624
|
|
|
|
|
|
|
|
|
|
|
|
Seismic and
other
|
|
|
5,237
|
|
|
|
2,470
|
|
Total exploration
costs
|
|
$
|
7,467
|
|
|
$
|
37,094
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
Depletion and Amortization (in thousands):
|
|
|
|
|
|
|
|
|
|
Oil and gas
depletion
|
|
$
|
50,339
|
|
|
$
|
29,879
|
|
|
Contract drilling
depreciation
|
|
|
4,400
|
|
|
|
3,245
|
|
|
Other
depreciation
|
|
|
508
|
|
|
|
594
|
|
|
Total
DD&A
|
|
$
|
55,247
|
|
|
$
|
33,718
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and Gas Costs ($/Mcfe Produced):
|
|
|
|
|
|
|
|
|
|
Production
costs
|
|
$
|
2.28
|
|
|
$
|
2.09
|
|
|
Oil and gas
depletion
|
|
$
|
2.70
|
|
|
$
|
1.78
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Wells Drilled
(b)
:
|
|
|
|
|
|
|
|
|
|
Exploratory
Wells
|
|
|
2.7
|
|
|
|
9.2
|
|
|
Developmental
Wells
|
|
|
35.7
|
|
|
|
9.2
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
No der
ivativ
es were designated as cash flow hedges in 2008 or
2007. All gains or losses on settled derivatives were included in
loss on derivatives.
|
|
|
(b)
Excludes wells
being drilled or completed at the end of each period.
|
|
|
Operating
Results – Three-Month Periods
The
following discussion compares our results for the three months ended June 30,
2008 to the comparative period in 2007. Unless otherwise indicated,
references to 2008 and 2007 within this section refer to the respective
quarterly period.
Oil
and gas operating results
Oil and
gas sales in 2008 increased $59.4 million, or 79%, from
2007. Price variances accounted for a $58.5 million increase, and
production variances accounted for a $900,000 increase. Production in
2008 (on an Mcfe basis) was 4% lower than 2007, despite significant additions
from our on-going developmental drilling programs, due to the loss of production
from the sale of South Louisiana assets in April 2008. Oil production
increased 22% in 2008 from 2007 and gas production decreased 19% in 2008 from
2007. The growth in oil production was attributed to in-fill drilling
in the Austin Chalk (Trend) and increased drilling activities in the Permian
Basin. As adjusted for the South Louisiana asset sale, gas production
was favorably impacted by incremental production from drilling activities in
North Louisiana. In 2008, our realized oil price was 94% higher than
2007, while our realized gas price was 54% higher. Historically, the
markets for oil and gas have been volatile, and they are likely to continue to
be volatile.
Production
costs, consisting of lease operating expenses, production taxes and other
miscellaneous marketing costs, increased 23% in 2008 as compared to
2007. Increases in oilfield service costs, higher repair and
maintenance costs, saltwater disposal fees and higher production taxes related
to higher commodity prices were key components for the rise in production
costs. It is likely that these factors will continue to contribute to
higher production costs in future periods. After giving effect to a
4% decrease in oil and gas production on an Mcfe basis, production costs per
Mcfe increased 28% from $1.99 per Mcfe in 2007 to $2.54 per Mcfe in
2008.
Oil and
gas depletion expense increased $6.3 million from 2007 to 2008, of which rate
variances accounted for a $6.8 million increase and production variances
accounted for a $500,000 decrease. On an Mcfe basis, depletion
expense increased 44% from $1.82 per Mcfe in 2007 to $2.62 per Mcfe in 2008 due
in part to a higher depletable cost basis in 2008 compared to the 2007
period. Depletion expense per Mcfe of oil and gas production is an
operating metric that is indicative of our weighted average cost to find or
acquire a unit of equivalent production. We may realize higher oil
and gas depletion rates in future periods if our exploration and development
activities result in higher finding costs.
Exploration
costs
Since we
follow the successful efforts method of accounting, our results of operations
are adversely affected during any accounting period in which significant seismic
costs, exploratory dry hole costs, and unproved acreage impairments are
expensed. In 2008, we charged to expense $3.5 of exploration costs, as
compared to $25.1 million in 2007.
At June
30, 2008, our capitalized unproved oil and gas properties totaled
$155.4 million, of which approximately $86.1 million was attributable
to unproved acreage. Unproved properties are subject to a valuation
impairment to the extent the carrying cost of a prospect exceeds its estimated
fair value. Therefore, our results of operations in future periods
may be adversely affected by unproved property impairments.
We plan
to spend approximately $400.7 million on exploration and development
activities in 2008, of which approximately 27% is expected to be allocated to
exploration activities. Since exploratory drilling involves a high degree
of risk, it is likely that a significant portion of the costs we incur in 2008
will be charged to exploration costs. However, we cannot predict our success
rates and, accordingly, cannot predict our exploration costs related to
abandonment and impairment costs.
Contract
Drilling Services
In April
2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc. to
construct, own, and operate 12 new drilling rigs. We own a 50%
interest in Larclay JV. Although the Company and Lariat own equal
interests in Larclay JV, the Company meets the definition of the primary
beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the
primary beneficiary under FIN 46R, the Company is required to include the
accounts of Larclay JV in the Company’s consolidated financial
statements. During the three months ended June 30, 2008, we included
contract drilling revenues of $16.9 million, other operating expenses of $12.8
million, depreciation expense of $2.6 million and interest expense of
$941,000 in our statement of operations (see Note 14 to the consolidated
financial statements). Since the Larclay JV drilling rigs are
partially utilized by us, the reported amounts are net of any intercompany
profits eliminated in consolidation.
General
and Administrative
General
and administrative (“G&A”) expenses increased 61% from $4.9 million in
2007 to $7.9 million in 2008. Excluding non-cash employee
compensation, G&A expenses increased from $4.4 million in 2007 to
$6.4 million in 2008 due primarily to cash bonuses paid to employees in
connection with our recent sale of properties in South Louisiana. In
2008, we recorded a $1.6 million non-cash charge related to our after payout
incentive plan, as compared to a $500,000 non-cash charge in 2007.
Interest
expense
Interest
expense decreased 24% from $8 million in 2007 to $6 million in 2008
due to a combination of reduced debt levels and lower interest rates. Debt
reductions accounted for $1.5 million of the decrease, while lower interest
rates resulted in a decrease of approximately $700,000. The average
daily principal balance outstanding under our revolving credit facility for 2008
was $94.1 million compared to $175 million for 2007. During
2008, we received approximately $114 million from the sale of assets and used
the net proceeds to reduce indebtedness outstanding under our revolving credit
facility. In addition, capitalized interest for 2008 was $907,000
compared to $1.1 million in 2007, and interest expense associated with our
Larclay JV during 2008 was $941,000 compared to $1 million in 2007.
Gain/loss
on derivatives
We did
not designate any derivative contracts in 2008 or 2007 as cash flow hedges;
therefore all cash settlements and changes resulting from mark-to-market
valuations have been recorded as gain/loss on derivatives. For the
three months ended June 30, 2008, we reported a $148.6 million net loss on
derivatives, consisting of a $113.6 million non-cash loss to mark our
derivative positions to their fair value at June 30, 2008 and a $35 million
realized loss on settled contracts. For the three months ended
June 30, 2007, we reported a $6.1 million net gain on derivatives,
consisting of a $7.6 million non-cash gain to mark our derivative positions
to their fair value at June 30, 2007 and a $1.5 million realized loss on
settled contracts. Because oil and gas prices are volatile, and
because we do not account for our derivatives as cash flow hedges, the effect of
mark-to-market valuations on our gain/loss on derivatives can cause significant
volatility in our results of operations.
Gain/loss
on sales of property and equipment
We
recorded a net gain of $40.4 million on sales of property and equipment which
included a $33.1 million gain on the sale of properties in South Louisiana and
$5.7 million gains on the sales of two drilling rigs and a surplus well
servicing unit compared to a $534,000 gain for sales of certain acreage in
2007.
Income
tax expense
Our
effective income tax rate in 2008 of 35.7% differed from the statutory federal
rate of 35% due primarily to increases in the tax provision related primarily to
the effects of the recently-enacted Texas Margin Tax and certain non-deductible
expenses, offset in part by tax benefits derived from excess statutory depletion
deductions.
Operating
Results – Six-Month Periods
The
following discussion compares our results for the six months ended June 30, 2008
to the comparative period in 2007. Unless otherwise indicated,
references to 2008 and 2007 within this section refer to the respective
quarterly period.
Oil
and gas operating results
Oil and
gas sales in 2008 increased $117.1 million, or 86%, from
2007. Price variances accounted for a $98.5 million increase, and
production variances accounted for a $18.6 million
increase. Production in 2008 (on an Mcfe basis) was 11% higher than
2007. Oil production increased 24% and gas production increased 3% in
2008 from 2007. The growth in oil production was attributed to
in-fill drilling in the Austin Chalk (Trend) and increased drilling activities
in the Permian Basin. Increases in gas production from our drilling
activities in North Louisiana were substantially offset by lower production in
South Louisiana caused by the sale of certain properties in April
2008. In 2008, our realized oil price was 85% higher than 2007, while
our realized gas price was 39% higher. Historically, the markets for
oil and gas have been volatile, and they are likely to continue to be
volatile.
Production
costs, consisting of lease operating expenses, production taxes and other
miscellaneous marketing costs, increased 21% in 2008 as compared to 2007 due
primarily to rising oilfield service costs, saltwater disposal fees and higher
repair and maintenance costs. In addition higher production taxes
related to higher commodity prices contributed to the increase in production
costs. It is likely that these factors will continue to contribute to
higher production costs in future periods. After giving effect to a
11% increase in oil and gas production on an Mcfe basis, production costs per
Mcfe increased 9% from $2.09 per Mcfe in 2007 to $2.28 per Mcfe in
2008.
Oil and
gas depletion expense increased $20.5 million from 2007 to 2008, of which
production variances accounted for a $3.2 million increase and rate
variances accounted for a $17.3 million increase. On an Mcfe
basis, depletion expense increased 52% from $1.78 per Mcfe in 2007 to $2.70 per
Mcfe in 2008 due in part to a higher depletable cost basis in 2008 compared to
the 2007 period. Depletion expense per Mcfe of oil and gas production
is an operating metric that is indicative of our weighted average cost to find
or acquire a unit of equivalent production. We may realize higher oil
and gas depletion rates in future periods if our exploration and development
activities result in higher finding costs.
Exploration
costs
Since we
follow the successful efforts method of accounting, our results of operations
are adversely affected during any accounting period in which significant seismic
costs, exploratory dry hole costs, and unproved acreage impairments are
expensed. In 2008, we charged to expense $7.5 of exploration costs, as
compared to $37.1 million in 2007. All of the 2008 costs were
incurred in Louisiana.
At June
30, 2008, our capitalized unproved oil and gas properties totaled
$155.4 million, of which approximately 86.1 million was attributable to
unproved acreage. Unproved properties are subject to a valuation
impairment to the extent the carrying cost of a prospect exceeds its estimated
fair value. Therefore, our results of operations in future periods
may be adversely affected by unproved property impairments.
We plan
to spend approximately $400.7 million on exploration and development activities
in 2008, of which approximately 27% is expected to be allocated to exploration
activities. Since exploratory drilling involves a high degree of
risk, it is likely that a significant portion of the costs we incur in 2008 will
be charged to exploration costs. However, we cannot predict our success rates
and, accordingly, cannot predict our exploration costs related to abandonment
and impairment costs.
Contract
Drilling Services
In April
2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc. to
construct, own, and operate 12 new drilling rigs. We own a 50%
interest in Larclay JV. Although the Company and Lariat own equal
interests in Larclay JV, the Company meets the definition of the primary
beneficiary of Larclay JV’s expected cash flows under
FIN
46R. As the primary beneficiary under FIN 46R, the Company is
required to include the accounts of Larclay JV in the Company’s consolidated
financial statements. During the six months ended June 30, 2008, we
included contract drilling revenues of $34 million, other operating expenses of
$25.8 million, depreciation expense of $5.2 million and interest expense of $2
million in our statement of operations (see Note 14 to the consolidated
financial statements). Since the Larclay JV drilling rigs are
partially utilized by us, the reported amounts are net of any intercompany
profits eliminated in consolidation.
General
and Administrative
General
and administrative (“G&A”) expenses increased 29% from $8.8 million in
2007 to $11.4 million in 2008. Excluding non-cash employee
compensation, G&A expenses increased from $7.7 million in 2007 to
$9.5 million in 2008 due primarily to cash bonuses paid to employees in
connection with our recent sale of properties in South Louisiana. In
2008, we recorded a $1.8 million non-cash compensation charge related to our
after payout incentive plan and $92,000 for stock-based employee
compensation. In 2007, we recorded a $1 million non-cash compensation
charge related to our after payout incentive plan and $110,000 for stock-based
employee compensation.
Interest
expense
Interest
expense decreased 13% from $15.6 million in 2007 to $13.5 million in
2008 due to a combination of reduced debt levels and lower interest rates. Debt
reductions accounted for $1.2 million of the decrease, while lower interest
rates resulted in a decrease of approximately $1.6 million. The
average daily principal balance outstanding under our revolving credit facility
for 2008 was $134.3 million compared to $167.1 million for
2007. During 2008, we received approximately $114 million from the
sale of assets and used the net proceeds to reduce indebtedness outstanding
under on our revolving credit facility. In addition, capitalized
interest for 2008 was $1.7 million compared to $2.1 million in 2007, and
interest expense associated with our Larclay JV during 2008 was $2 million
compared to $1.9 million in 2007.
Gain/loss
on derivatives
We did
not designate any derivative contracts in 2008 or 2007 as cash flow hedges;
therefore all cash settlements and changes resulting from mark-to-market
valuations have been recorded as gain/loss on derivatives. For the
six months ended June 30, 2008, we reported a $194.7 million net loss on
derivatives, consisting of a $145.6 million non-cash loss to mark our
derivative positions to their fair value at June 30, 2008 and a
$49.1 million realized loss on settled contracts. For the six
months ended June 30, 2007, we reported a $10.7 million net loss on
derivatives, consisting of a $11.2 million non-cash loss to mark our derivative
positions to their fair value at June 30, 2007 and a $500,000 realized gain on
settled contracts. Because oil and gas prices are volatile, and
because we do not account for our derivatives as cash flow hedges, the effect of
mark-to-market valuations on our gain/loss on derivatives can cause significant
volatility in our results of operations.
Gain/loss
on sales of property and equipment
We
recorded a net gain on sales of property and equipment of $41 million for 2008
which included a $33.1 million gain on sales of properties in South Louisiana
and $5.7 million gains on the sales of two drilling rigs and a surplus well
servicing unit compared to a net loss of $8.5 million which included losses on
inventory during 2007 of $9.2 million, including a non-cash charge of $8.9
million to write-down inventory to its estimated market value at June 30,
2007. The write-down resulted primarily from the sale of certain
surplus equipment at an auction in March 2007. No write-downs were
recorded during the 2008 period.
Income
tax expense
Our
effective income tax rate in 2008 of 35.1% differed from the statutory federal
rate of 35% due primarily to increases in the tax provision related primarily to
the effects of the recently-enacted Texas Margin Tax and certain non-deductible
expenses, offset in part by tax benefits derived from statutory depletion
deductions.
Liquidity
and Capital Resources
Overview
Our
primary financial resource is our base of oil and gas reserves. We
pledge our producing oil and gas properties to a group of banks to secure our
revolving credit facility. The banks establish a borrowing base by
making an estimate of the collateral value of our oil and gas
properties. We borrow funds on the revolving credit facility as
needed to supplement our operating cash flow as a financing source for our
capital expenditure program. Our ability to fund our capital
expenditure program is dependent upon the level of product prices and the
success of our exploration program in replacing our existing oil and gas
reserves. If product prices decrease, our operating cash flow may
decrease and the banks may require additional collateral or reduce our borrowing
base, thus reducing funds available to fund our capital expenditure
program. The effects of product prices on cash flow can be mitigated
through the use of commodity derivatives. If we are unable to replace our oil
and gas reserves through our exploration program, we may also suffer a reduction
in our operating cash flow and access to funds under the revolving credit
facility. Under extreme circumstances, product price reductions or
exploration drilling failures could allow the banks to seek to foreclose on our
oil and gas properties, thereby threatening our financial
viability.
In 2005,
we issued $225 million of aggregate principal amount of Senior Notes and
used the net proceeds to repay all amounts outstanding on the revolving credit
facility at that time. Since then, we have relied on advances under
our revolving credit facility to finance a portion of our exploration and
development activities. During the first half of 2008, we completed
certain asset sales for aggregate proceeds of approximately $114 million and
applied the net proceeds to reduce indebtedness outstanding under our revolving
credit facility. At June 30, 2008, we had $50 million outstanding
under the revolving credit facility.
Our 2008
expenditures may exceed our cash flow from operating activities in
2008. We cannot predict our drilling success on exploratory
prospects, and our future results of operations and financial condition could be
adversely affected by unsuccessful exploratory drilling results. In
this section, we will describe our current plans for capital spending, identify
the capital resources available to finance our capital spending, and discuss the
principal factors that can affect our liquidity and capital
resources.
Capital
expenditures
We
incurred expenditures for exploration and development activities of $154.7
million during the first six months of 2008 and have increased our estimates for
planned expenditures for fiscal 2008 from $344.5 million to
$400.7 million. The following table summarizes, by area, our
actual expenditures for exploration and development activities for the first
half of 2008 and our planned expenditures for the year ending December 31,
2008.
|
|
Actual
|
|
|
Planned
|
|
|
|
|
|
|
Expenditures
|
|
|
Expenditures
|
|
|
Year
2008
|
|
|
|
Six
Months Ended
|
|
|
Year
Ending
|
|
|
Percentage
|
|
|
|
June
30, 2008
|
|
|
December
31, 2008
|
|
|
of
Total
|
|
|
|
(In
thousands)
|
|
|
|
|
Permian
Basin
|
|
$
|
60,400
|
|
|
$
|
184,100
|
|
|
|
46
|
%
|
North
Louisiana
|
|
|
34,600
|
|
|
|
83,400
|
|
|
|
21
|
%
|
Austin
Chalk
(Trend)
|
|
|
28,600
|
|
|
|
57,500
|
|
|
|
14
|
%
|
South
Louisiana
|
|
|
17,000
|
|
|
|
35,700
|
|
|
|
9
|
%
|
East
Texas
Bossier
|
|
|
11,800
|
|
|
|
30,300
|
|
|
|
8
|
%
|
Utah/California
|
|
|
1,900
|
|
|
|
8,700
|
|
|
|
2
|
%
|
Other
|
|
|
400
|
|
|
|
1,000
|
|
|
|
-
|
|
|
|
$
|
154,700
|
|
|
$
|
400,700
|
|
|
|
100
|
%
|
Our
actual expenditures during fiscal 2008 may be substantially higher or lower than
these estimates since our plans for exploration and development activities may
change during the remainder of the year. Other factors, such as
prevailing product prices and the availability of capital resources, could also
increase or decrease the ultimate level of expenditures during fiscal
2008.
Approximately
27% of the 2008 planned expenditures relate to exploratory
prospects. Exploratory prospects involve a higher degree of risk than
developmental prospects. To offset the higher risk, we generally
strive to achieve a higher reserve potential and rate of return on investments
in exploratory prospects. We do not attempt to forecast our success
rate on exploratory drilling. Accordingly, these current estimates do
not include costs we may incur to complete any future successful exploratory
wells and construct the required production facilities for these
wells. Also, we are actively searching for other opportunities to
increase our oil and gas reserves, including the evaluation of new prospects for
exploratory and developmental drilling activities and potential acquisitions of
proved oil and gas properties. We cannot predict our drilling success
on exploratory prospects, and our future results of operations and financial
condition could be adversely affected by unsuccessful exploratory drilling
results.
Our
expenditures for exploration and development activities for the six months ended
June 30, 2008 totaled $154.7 million, of which approximately 19% was on
exploratory prospects. We currently plan to spend approximately
$400.7 million for the calendar year 2008, of which approximately 27% is
estimated to be spent on exploratory prospects. Our 2008 expenditures
may also exceed our cash flow from operating activities in 2008. To
the extent possible, we intend to finance this shortfall by borrowings on the
revolving credit facility. During the first half of 2008, we
completed the sale of certain properties in South Louisiana and the sale of two
drilling rigs and a well servicing unit for aggregate net proceeds of
approximately $114 million, and applied the net proceeds to reduce indebtedness
outstanding under our revolving credit facility. Our internal cash
flow forecasts indicate that the amount of funds available to us under our
revolving credit facility, when combined with our anticipated operating cash
flow, will be sufficient to finance our capital expenditures and will provide us
with adequate liquidity at least through the end of 2008. Although we
believe the assumptions and estimates made in our forecasts are reasonable,
uncertainties exist which could cause the borrowing base to be less than
expected, cash flow to be less than expected, or capital expenditures to be more
than expected. In the event we lack adequate liquidity to finance our
expenditures in 2008, we will consider options for alternative capital
resources, including the sale of assets.
Cash
flow provided by operating activities
Substantially
all of our cash flow from operating activities
is derived
from the production of our oil and gas reserves. We use this
cash flow to fund our on-going exploration and development activities in search
of new oil and gas reserves. Variations in cash flow from operating
activities may impact our level of exploration and development
expenditures.
Cash flow
provided by operating activities for the six months ended June 30, 2008
increased $59.5 million, or 66.1%, as compared to the corresponding period
in 2007. Approximately $4.6 million of the increase in operating cash
flow was attributable to Larclay JV. All of Larclay JV’s cash flow is
dedicated to the repayment of a $75 million secured term loan
facility. The remainder of the increase in operating cash flow was
derived primarily from oil and gas producing activities, offset in part by
increases in production costs and seismic expenses.
Credit
facility
A group
of banks have provided us with a revolving credit facility on which we have
historically relied for both our short-term liquidity (working capital) and our
long-term financing needs. The funds available to us at any time
under this revolving credit facility are limited to the amount of the borrowing
base established by the banks. As long as we have sufficient
availability under this credit facility to meet our obligations as they come
due, we will have sufficient liquidity and will be able to fund any short-term
working capital deficit.
During
the first six months in 2008, we repaid $115.8 million on the revolving credit
facility primarily from the sale of assets. At June 30, 2008, we had
a borrowing base of $250 million, leaving $199.2 million available
under the revolving loan facility after accounting for outstanding letters of
credit of $804,000.
Using the
revolving credit facility for both our short-term liquidity and long-term
financing needs can cause unusual fluctuations in our reported working capital,
depending on the timing of cash receipts and expenditures. On a daily
basis, we use most of our available cash to pay down our outstanding balance on
the revolving credit facility, which is classified as a non-current liability
since we currently have no required principal reductions. As we use
cash to pay a non-current liability, our reported working capital
decreases. Conversely, as we draw on the revolving credit
facility
for funds to pay current liabilities (such as payables for drilling and
operating costs), our reported working capital increases. Also,
volatility in oil and gas prices can cause significant fluctuations in reported
working capital as we record changes in the fair value of derivatives from
period to period. For these reasons, the working capital covenant
related to the revolving credit facility requires us to (i) include the
amount of funds available under this facility as a current asset,
(ii) exclude current assets and liabilities related to the fair value of
derivatives, and (iii) exclude current maturities of vendor finance
obligations, if any, when computing the working capital ratio at any balance
sheet date.
Working
capital computed for loan compliance purposes differs from our working capital
in accordance with generally accepted accounting principles
(GAAP). Since compliance with financial covenants is a material
requirement under the credit facilities, we consider the loan compliance working
capital to be useful as a measure of our liquidity because it includes the funds
available to us under the revolving credit facility and is not affected by the
volatility in working capital caused by changes in fair value of
derivatives. Our GAAP reported working capital deficit increased from
$76.4 million at December 31, 2007 to $190.6 million at June 30,
2008 due primarily to decreases in other current assets related to assets held
for sale and an increase in the net liability for the fair value for
derivatives. After giving effect to the adjustments, our working
capital computed for loan compliance purposes was a positive $173.2 million
at June 30, 2008, as compared to a positive $103.2 million at
December 31, 2007. The following table reconciles our GAAP
working capital to the working capital computed for loan compliance purposes at
June 30, 2008 and December 31, 2007.
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Working
capital (deficit) per GAAP
|
|
$
|
(190,584
|
)
|
|
$
|
(76,388
|
)
|
Add
funds available under the revolving credit facility
|
|
|
199,196
|
|
|
|
108,396
|
|
Exclude
fair value of derivatives classified as current assets or current
liabilities
|
|
|
147,506
|
|
|
|
49,738
|
|
Exclude
current assets and current liabilities of Larclay JV
|
|
|
17,039
|
|
|
|
21,423
|
|
Working
capital per loan covenant
|
|
$
|
173,157
|
|
|
$
|
103,169
|
|
Since we
use this revolving credit facility for both short-term liquidity and long-term
financing needs, it is important that we comply in all material respects with
the loan agreement, including financial covenants that are computed
quarterly. The working capital covenant requires us to maintain
positive working capital using the computations described
above. Another financial covenant under the credit facility requires
us to maintain a ratio of indebtedness to cash flow of no more than 3 to
1. While we were in compliance with all financial and non-financial
covenants at June 30, 2008, our increased leverage and reduced liquidity may
result in our failing to comply with one or more of these covenants in the
future. If we fail to meet any of these loan covenants, we would ask the
banks to allow us sufficient time to obtain additional capital resources through
alternative means. If a suitable arrangement could not be reached
with the banks, the banks could accelerate the indebtedness and seek to
foreclose on the pledged assets.
The banks
redetermine the borrowing base under the revolving credit facility at least
twice a year, in May and November. The borrowing base was reduced in
May 2008 from $275 million to $250 million in connection with our sale of
certain properties in South Louisiana. In June 2008, we elected to
hold the borrowing base at $250 million instead of increasing it to levels
supported by the collateral values assigned by the banks. If at any
time, the borrowing base is less than the amount of outstanding indebtedness, we
will be required to (i) pledge additional collateral, (ii) prepay the
excess in not more than five equal monthly installments, or (iii) elect to
convert the entire amount of outstanding indebtedness to a term obligation based
on amortization formulas set forth in the loan agreement. We have
relied heavily on advances under the revolving credit facility to finance a
significant portion of our exploration and development activities in fiscal 2007
and the first half of 2008. At June 30, 2008, we had $50 million
outstanding on the revolving credit facility.
In June
2008, we amended our loan agreement with the banks to extend the maturity of the
credit facility from 2009 to 2012, to modify certain covenants restricting the
Company’s ability to engage in hedging transactions, including limits on hedging
transactions for the remainder of 2008 and to waive noncompliance with
prior limitations on hedging transactions.
7¾%
Senior Notes due 2013
In July
2005, we issued, in a private placement, $225 million of aggregate
principal amount of Senior Notes. The Senior Notes were issued at
face value and bear interest at 7¾% per year, payable semi-annually on February
1 and August 1 of each year, beginning February 1, 2006. After the
payment of typical transaction expenses, net proceeds of approximately
$217 million were used to repay amounts outstanding on our secured credit
facilities and for general corporate purposes, including the funding of planned
exploration and development activities.
At any
time prior to August 1, 2008, we may redeem up to 35% of the aggregate principal
amount of the Senior Notes with the proceeds of certain equity offerings at a
redemption price of 107.75% of the principal amount, plus accrued and unpaid
interest. In addition, prior to August 1, 2009, we may redeem some or
all of the Senior Notes at a redemption price equal to 100% of the principal
amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any
accrued and unpaid interest. On and after August 1, 2009, we may
redeem some or all of the Senior Notes at redemption prices (expressed as
percentages of principal amount) equal to 103.875% for the twelve-month period
beginning on August 1, 2009, 101.938% for the twelve-month period beginning
on August 1, 2010, and 100.00% beginning on August 1, 2011, for any period
thereafter, in each case plus accrued and unpaid interest.
The
Indenture governing the Senior Notes restricts our ability and the ability of
our restricted subsidiaries to: (i) borrow money;
(ii) issue redeemable or preferred stock; (iii) pay distributions or
dividends; (iv) make investments; (v) create liens without securing
the Notes; (vi) enter into agreements that restrict dividends from
subsidiaries; (vii) sell certain assets or merge with or into other
companies; (viii) enter into transactions with affiliates;
(ix) guarantee indebtedness; and (x) enter into new lines of
business. These covenants are subject to a number of important
exceptions and qualifications. We were in compliance with these
covenants at June 30, 2008.
Alternative
capital resources
Although
our base of oil and gas reserves, as collateral for both of our credit
facilities, has historically been our primary capital resource, we have in the
past, and we believe we could in the future, use alternative capital resources,
such as asset sales, vendor financing arrangements, and/or public or private
issuances of common stock. We could also issue senior or subordinated
debt or preferred stock in a public or a private placement if we choose to raise
capital through either of these markets. While we believe we would be
able to obtain funds through one or more of these alternatives, if needed, there
can be no assurance that these capital resources would be available on terms
acceptable to us.
Item 3
-
Quan
titative
and Qualitative Disclosures About Market
Risks
Our
business is impacted by fluctuations in commodity prices and interest
rates. The following discussion is intended to identify the nature of
these market risks, describe our strategy for managing such risks, and to
quantify the potential affect of market volatility on our financial condition
and results of operations.
Oil
and Gas Prices
Our
financial condition, results of operations, and capital resources are highly
dependent upon the prevailing market prices of, and demand for, oil and natural
gas. These commodity prices are subject to wide fluctuations and
market uncertainties due to a variety of factors that are beyond our
control. These factors include the level of global demand for
petroleum products, foreign supply of oil and gas, the establishment of and
compliance with production quotas by oil-exporting countries, weather
conditions, the price and availability of alternative fuels, and overall
economic conditions, both foreign and domestic. We cannot predict
future oil and gas prices with any degree of certainty. Sustained
weakness in oil and gas prices may adversely affect our financial condition and
results of operations, and may also reduce the amount of net oil and gas
reserves that we can produce economically. Any reduction in reserves,
including reductions due to price fluctuations, can reduce the borrowing base
under our revolving credit facility and adversely affect our liquidity and our
ability to obtain capital for our exploration and development
activities. Similarly, any improvements in oil and gas prices can
have a favorable impact on our financial condition, results of operations and
capital resources. Based on December 31, 2007 reserve estimates,
we project that a $1 drop in
the price
per Bbl of oil and a $.50 drop in the price per Mcf of gas from year end 2007
would reduce our gross revenues for the year ending December 31, 2008 by
$12.4 million.
From time
to time, we utilize commodity derivatives, consisting primarily of swaps, floors
and collars to attempt to optimize the price received for our oil and natural
gas production. When using swaps to hedge our oil and natural gas
production, we receive a fixed price for the respective commodity and pay a
floating market price as defined in each contract (generally NYMEX futures
prices), resulting in a net amount due to or from the
counterparty. When purchasing floors, we receive a fixed price (put
strike price) if the market price falls below the put strike price for the
respective commodity. If the market price is greater than the put
strike price, no payments are due from either party. Costless collars
are a combination of puts and calls, and contain a fixed floor price (put strike
price) and ceiling price (call strike price). If the market price for
the respective commodity exceeds the call strike price or falls below the put
strike price, then we receive the fixed price and pay the market
price. If the market price is between the call and the put strike
prices, no payments are due from either party. The commodity
derivatives we use differ from futures contracts in that there is not a
contractual obligation that requires or permits the future physical delivery of
the hedged products. We do not enter into commodity derivatives for
trading purposes. In addition to commodity derivatives, we may, from
time to time, sell a portion of our gas production under short-term contracts at
fixed prices.
The
decision to initiate or terminate commodity hedges is made by management based
on its expectation of future market price movements. We have no set
goals for the percentage of our production we hedge and we do not use any
formulas or triggers in deciding when to initiate or terminate a
hedge. If we enter into swaps or collars and the floating market
price at the settlement date is higher than the fixed price or the fixed ceiling
price, we will forego revenue we would have otherwise received. If we
terminate a swap, collar or floor because we anticipate future increases in
market prices, we may be exposed to downside risk that would not have existed
otherwise.
The
following summarizes information concerning our net positions in open commodity
derivatives applicable to periods subsequent to June 30, 2008. The
settlement prices of commodity derivatives are based on NYMEX futures
prices.
Collars:
|
|
Gas
|
|
|
Oil
|
|
|
|
MMBtu
(a)
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Bbls
|
|
|
Floor
|
|
|
Ceiling
|
|
Production
Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
rd
Quarter 2008
|
|
|
419,000
|
|
|
$
|
4.00
|
|
|
$
|
5.15
|
|
|
|
128,000
|
|
|
$
|
23.00
|
|
|
$
|
25.07
|
|
Swaps:
|
|
Gas
|
|
|
Oil
|
|
|
|
MMBtu
(a)
|
|
|
Price
|
|
|
Bbls
|
|
|
Price
|
|
Production
Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
3
rd
Quarter 2008
|
|
|
4,000,000
|
|
|
$
|
9.19
|
|
|
|
310,000
|
|
|
$
|
78.96
|
|
4
th
Quarter
2008
|
|
|
4,100,000
|
|
|
$
|
9.17
|
|
|
|
400,000
|
|
|
$
|
82.21
|
|
2009
|
|
|
3,600,000
|
|
|
$
|
9.33
|
|
|
|
1,440,000
|
|
|
$
|
85.30
|
|
|
|
|
11,700,000
|
|
|
|
|
|
|
|
2,150,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
One
MMBtu equals one Mcf at a Btu factor of 1,000.
|
|
In July
2008, the Company terminated certain fixed-price gas swaps covering 300,000
MMBtu at a price of $10.32 per MMBtu from August 2008 through October 2008,
resulting in an aggregate loss of $585,000, which will be paid to the
counterparty monthly as the applicable contracts are settled.
In
September 2007, the Company terminated certain fixed-priced oil swaps covering
60,000 barrels at a price of $76.65 from July 2008 through December 2008,
resulting in an aggregate loss of approximately $663,000, which will be paid to
the counterparty monthly as the applicable contracts are settled.
We use a
sensitivity analysis technique to evaluate the hypothetical effect that changes
in the market value of oil and gas may have on the fair value of our commodity
derivatives. A $1 per barrel change in the price of oil and a
$.50 per MMBtu change in the price of gas would change the fair value of our
commodity derivatives by approximately $7.5 million.
Interest
Rates
We are
exposed to interest rate risk on our long-term debt with a variable interest
rate. At June 30, 2008, our variable rate debt had a carrying value
of $50 million, which approximated its fair value. At June 30, 2008,
our fixed rate debt had a carrying value of $225 million and an approximate
fair value of $216 million, based on current market quotes. We
estimate that the hypothetical change in the fair value of our fixed-rate,
long-term debt resulting from a 100-basis point change in interest rates would
be approximately $8.7 million. Based on our outstanding variable
rate indebtedness at June 30, 2008 of $50 million, a change in interest rates of
100 basis points would affect annual interest payments by $500,000.
We are a
party to an interest rate swap. Under this derivative, we pay a fixed
rate for the notional principal balance and receive a floating market rate based
on LIBOR. The interest rate swap is settled quarterly. The
following summarizes information concerning our interest rate swap at June 30,
2008.
Interest
Rate Swap:
|
|
|
|
|
Fixed
|
|
|
|
Principal
|
|
|
Libor
|
|
|
|
Balance
|
|
|
Rates
|
|
Period:
|
|
|
|
|
|
|
July 1, 2008 to November 3,
2008
|
|
$
|
45,000,000
|
|
|
|
5.73
|
%
|
The
interest rate swap in the preceding table exposes us to market risks for
decreases in interest rates during the periods shown.
In April
2008, the Company terminated its $100 million interest rate swap for a cash
payment of $899,000.
Item 4
-
Controls and
Procedures
Disclosure
Controls and Procedures
In
September 2002, our Board of Directors adopted a policy designed to establish
disclosure controls and procedures that are adequate to provide reasonable
assurance that our management will be able to collect, process and disclose both
financial and non-financial information, on a timely basis, in our reports to
the Securities and Exchange Commission (“SEC”) and other communications with our
stockholders. Disclosure controls and procedures include all
processes necessary to ensure that material information is recorded, processed,
summarized and reported within the time periods specified in the SEC’s rules and
forms, and is accumulated and communicated to our management, including our
chief executive and chief financial officers, to allow timely decisions
regarding required disclosures.
With
respect to our disclosure controls and procedures:
·
|
Management
has evaluated the effectiveness of our disclosure controls and procedures
as of the end of the period covered by this
report;
|
·
|
This
evaluation was conducted under the supervision and with the participation
of our management, including our chief executive and chief financial
officers; and
|
·
|
It
is the conclusion of our chief executive officer and our chief financial
officer that these disclosure controls and procedures are effective in
ensuring that information that is required to be disclosed by the Company
in reports filed or submitted with the SEC is recorded, processed,
summarized and reported within the time periods specified in the rules and
forms established by the SEC.
|
Changes
in Internal Control Over Financial Reporting
No
changes in internal control over financial reporting were made during the
quarter ended June 30, 2008 that have materially affected, or are reasonably
likely to materially affect, our internal control over financial
reporting.
PART
II. OTHER INFORMATION
Item 1A
-
Risk
Factors
In
evaluating all forward-looking statements, you should specifically consider
various factors that may cause actual results to vary from those contained in
the forward-looking statements. Our risk factors are included in our
Annual Report on Form 10-K for the year ended December 31, 2007, as
filed with the U.S. Securities and Exchange Commission on March 14, 2008
and available at www.sec.gov. There have been no material changes to
these risk factors since the filing of our Form 10-K.
Item 4
-
Sub
missio
n of Matters to a Vote of Security
Holders
On May 7,
2008, we held our Annual Meeting of Stockholders to (a) elect three directors to
the Board of Directors for a term of three years, and (b) advise on the
selection of KPMG LLP as our independent auditors for 2008. At such
meeting Davis L. Ford, Robert L. Parker and Jordan R. Smith were reelected as
directors, and stockholders advised that KPMG LLP should be selected as our
independent auditors for 2008.
The
following is a summary of the votes cast at the Annual Meeting:
|
|
Results
of Voting
|
|
Votes
For
|
|
|
Withheld
|
|
|
|
1.
|
|
Election
of Directors
|
|
|
|
|
|
|
|
|
|
|
Davis L. Ford.
|
|
|
8,994,080
|
|
|
|
1,099,592
|
|
|
|
|
|
Robert L.
Parker
|
|
|
6,108,955
|
|
|
|
3,984,717
|
|
|
|
|
|
Jordan R.
Smith
|
|
|
8,832,194
|
|
|
|
1,261,478
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Votes
For
|
|
|
Withheld
|
|
Abstentions
|
|
2.
|
|
Advisory
vote on the selection of KPMG LLP
|
|
|
10,061,587
|
|
|
|
24,985
|
|
7,100
|
Item 6
-
Exhibits
Exhibits
**3.1
|
|
Second
Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1
to our Form S-2 Registration Statement, Commission File No.
333-13441
|
|
|
|
**3.2
|
|
Certificate
of Amendment of Second Restated Certificate of Incorporation of Clayton
Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the
period ended September 30, 2000††
|
|
|
|
**3.3
|
|
Corporate
Bylaws of Clayton Williams Energy, Inc., as amended, filed as
Exhibit 3.1 to our Current Report on Form 8-K filed with the
Commission on March 14, 2008††
|
|
|
|
**4.1
|
|
Indenture,
dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary
Guarantors and Wells Fargo Bank, National Association, as Trustee, filed
as Exhibit 4.1 to our Current Report on Form 8-K filed with the
Commission on July 22, 2005††
|
|
|
|
**10.1
|
|
Fifth
Amendment to Amended and Restated, dated June 13, 2008, among Clayton
Williams Energy, Inc., JP Morgan Chase Bank, N.A. and the other
signatories thereto, filed as Exhibit 10.1 to our Current Report on Form
8-K filed with the Commission on June 18, 2008.
††
|
|
|
|
**10.2†
|
|
Amaker-Tippet
Reward Plan dated June 19, 2008 filed as Exhibit 10.1 to our Current
Report on Form 8-K with the Commission on June 25, 2008.
††
|
|
|
|
**10.3†
|
|
Austin
Chalk Reward Plan dated June 19, 2008 filed as Exhibit 10.2 to our Current
Report on Form 8-K with the Commission on June 25, 2008.
††
|
|
|
|
**10.4†
|
|
Barstow
Area Reward Plan dated June 19, 2008 filed as Exhibit 10.3 to our Current
Report on Form 8-K with the Commission on June 25, 2008.
††
|
|
|
|
**10.5†
|
|
Participation
Agreement relating to Andrews Area dated June 19, 2008 filed as Exhibit
10.1 to our Current Report on Form 8-K filed with the Commission June 25,
2008. ††
|
|
|
|
**10.6†
|
|
Participation
Agreement relating to Crockett County Area dated June 19, 2008 filed as
Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission
June 25, 2008. ††
|
|
|
|
**10.7†
|
|
Participation
Agreement relating to North Louisiana Bossier III dated June 19, 2008
filed as Exhibit 10.3 to our Current Report on Form 8-K filed with the
Commission June 25, 2008. ††
|
|
|
|
**10.8†
|
|
Participation
Agreement relating to North Louisiana Hosston/Cotton Valley III dated
June 19, 2008 filed as Exhibit 10.4 to our Current Report on Form 8-K
filed with the Commission June 25, 2008. ††
|
|
|
|
**10.9†
|
|
Participation
Agreement relating to South Louisiana VI dated June 19, 2008 filed as
Exhibit 10.5 to our Current Report on Form 8-K filed with the Commission
June 25, 2008. ††
|
|
|
|
**10.10†
|
|
Participation
Agreement relating to Utah dated June 19, 2008 filed as Exhibit 10.6 to
our Current Report on Form 8-K filed with the Commission June 25, 2008.
††
|
|
|
|
*21
|
|
Subsidiaries
of the registrant
|
|
|
|
*31.1
|
|
Certification
by the President and Chief Executive Officer of the Company pursuant to
Rule 13a - 14(a) of the Securities Exchange Act of
1934
|
|
|
|
*31.2
|
|
Certification
by the Chief Financial Officer of the Company pursuant to Rule
13a - 14(a) of the Securities Exchange Act of
1934
|
|
|
|
*32.1
|
|
Certifications
by the Chief Executive Officer and Chief Financial Officer of the Company
pursuant to
18 U.S.C. § 1350
|
**
|
Incorporated
by reference to the filing
indicated
|
|
†
|
Identifies
an Exhibit that consists of or includes a management contract or
compensatory plan or arrangement
|
††
|
Filed
under our Commission File
No. 001-10924
|
CLAYTON
WILLIAMS ENERGY, INC.
SIG
NAT
URES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereto
duly authorized.
|
|
CLAYTON
WILLIAMS ENERGY, INC.
|
Date:
|
August
8, 2008
|
By:
|
/s/
L. Paul Latham
|
|
|
|
L.
Paul Latham
|
|
|
|
Executive
Vice President and Chief
|
|
|
|
Operating
Officer
|
Date:
|
August
8, 2008
|
By:
|
/s/
Mel G. Riggs
|
|
|
|
Mel
G. Riggs
|
|
|
|
Senior
Vice President and Chief Financial
|
|
|
|
Officer
|
42
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