UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
(Mark
One)
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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 March 31, 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.)
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Six
Desta Drive - Suite 6500
|
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|
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 12,104,051 shares of Common Stock, $.10 par value, of the registrant
outstanding as of May 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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22
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33
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35
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PART
II. OTHER INFORMATION
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36
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36
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37
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CLAYTON WILLIAMS
ENERGY, INC.
CONSOLIDATED
BALANCE SHEETS
(Dollars
in thousands)
ASSETS
|
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
18,523
|
|
|
$
|
12,344
|
|
Accounts
receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales,
net
|
|
|
48,991
|
|
|
|
36,698
|
|
Joint interest and other,
net
|
|
|
18,241
|
|
|
|
16,666
|
|
Affiliates
|
|
|
9,608
|
|
|
|
308
|
|
Inventory
|
|
|
14,896
|
|
|
|
14,348
|
|
Deferred income
taxes
|
|
|
3,581
|
|
|
|
3,581
|
|
Fair value of
derivatives
|
|
|
-
|
|
|
|
7,191
|
|
Assets held for
sale
|
|
|
72,135
|
|
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|
17,281
|
|
Prepaids and
other
|
|
|
3,583
|
|
|
|
3,962
|
|
|
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|
189,558
|
|
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|
112,379
|
|
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|
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|
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PROPERTY
AND EQUIPMENT
|
|
|
|
|
|
|
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|
Oil and gas properties,
successful efforts
method
|
|
|
1,313,786
|
|
|
|
1,374,090
|
|
Natural gas gathering and
processing
systems
|
|
|
18,604
|
|
|
|
18,404
|
|
Contract drilling
equipment
|
|
|
89,965
|
|
|
|
89,956
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|
Other
|
|
|
14,536
|
|
|
|
14,505
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|
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1,436,891
|
|
|
|
1,496,955
|
|
Less accumulated depreciation,
depletion and amortization
|
|
|
(736,153
|
)
|
|
|
(765,877
|
)
|
Property and equipment,
net
|
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|
700,738
|
|
|
|
731,078
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OTHER
ASSETS
|
|
|
|
|
|
|
|
|
Debt issue costs,
net
|
|
|
6,615
|
|
|
|
6,963
|
|
Fair value of
derivatives
|
|
|
72
|
|
|
|
-
|
|
Other
|
|
|
11,059
|
|
|
|
10,676
|
|
|
|
|
17,746
|
|
|
|
17,639
|
|
|
|
$
|
908,042
|
|
|
$
|
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
|
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
|
CURRENT
LIABILITIES
|
|
|
|
|
|
|
Accounts
payable:
|
|
|
|
|
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|
Trade
|
|
$
|
84,602
|
|
|
$
|
72,477
|
|
Oil and gas
sales
|
|
|
27,954
|
|
|
|
24,806
|
|
Affiliates
|
|
|
2,190
|
|
|
|
1,747
|
|
Current maturities of
long-term
debt
|
|
|
20,625
|
|
|
|
22,500
|
|
Fair value of
derivatives
|
|
|
71,646
|
|
|
|
56,929
|
|
Accrued liabilities and
other
|
|
|
5,884
|
|
|
|
10,308
|
|
|
|
|
212,901
|
|
|
|
188,767
|
|
|
|
|
|
|
|
|
|
|
NON-CURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
414,688
|
|
|
|
430,175
|
|
Deferred income
taxes
|
|
|
48,633
|
|
|
|
44,302
|
|
Fair value of
derivatives
|
|
|
10,192
|
|
|
|
-
|
|
Other
|
|
|
37,371
|
|
|
|
37,046
|
|
|
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|
510,884
|
|
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511,523
|
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|
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COMMITMENTS
AND CONTINGENCIES
|
|
|
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|
|
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STOCKHOLDERS’
EQUITY
|
|
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Preferred stock, par value
$.10 per share, authorized – 3,000,000
|
|
|
|
|
|
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shares; none
issued
|
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|
-
|
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|
-
|
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Common stock, par value $.10
per share, authorized – 30,000,000
|
|
|
|
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|
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shares; issued and
outstanding – 12,104,051 shares in 2008
|
|
|
|
|
|
|
|
|
and 11,354,051 shares in
2007
|
|
|
1,210
|
|
|
|
1,135
|
|
Additional paid-in
capital
|
|
|
136,831
|
|
|
|
121,063
|
|
Retained
earnings
|
|
|
43,069
|
|
|
|
35,890
|
|
Accumulated other
comprehensive income, net of tax
|
|
|
3,147
|
|
|
|
2,718
|
|
|
|
|
184,257
|
|
|
|
160,806
|
|
|
|
$
|
908,042
|
|
|
$
|
861,096
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON WILLIAMS
ENERGY, INC.
CONSOLIDATED
STATEMENTS OF OPERATIONS
(Unaudited)
(In
thousands, except per share)
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
Oil and gas
sales
|
|
$
|
118,919
|
|
|
$
|
61,180
|
|
Natural gas
services
|
|
|
2,538
|
|
|
|
2,654
|
|
Drilling rig
services
|
|
|
14,832
|
|
|
|
8,417
|
|
Gain on sales of property and
equipment
|
|
|
569
|
|
|
|
259
|
|
Total
revenues
|
|
|
136,858
|
|
|
|
72,510
|
|
|
|
|
|
|
|
|
|
|
COSTS
AND EXPENSES
|
|
|
|
|
|
|
|
|
Production
|
|
|
20,579
|
|
|
|
17,278
|
|
Exploration:
|
|
|
|
|
|
|
|
|
Abandonments and
impairments
|
|
|
297
|
|
|
|
11,105
|
|
Seismic and
other
|
|
|
3,675
|
|
|
|
890
|
|
Natural gas
services
|
|
|
2,515
|
|
|
|
2,413
|
|
Drilling rig
services
|
|
|
11,117
|
|
|
|
4,933
|
|
Depreciation, depletion and
amortization
|
|
|
30,273
|
|
|
|
15,231
|
|
Impairment of property and
equipment
|
|
|
-
|
|
|
|
565
|
|
Accretion of abandonment
obligations
|
|
|
530
|
|
|
|
618
|
|
General and
administrative
|
|
|
3,448
|
|
|
|
3,903
|
|
Loss on sales of property and
equipment
|
|
|
9
|
|
|
|
9,332
|
|
Total costs and
expenses
|
|
|
72,443
|
|
|
|
66,268
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
64,415
|
|
|
|
6,242
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
(7,446
|
)
|
|
|
(7,629
|
)
|
Loss on
derivatives
|
|
|
(46,109
|
)
|
|
|
(16,849
|
)
|
Other
|
|
|
655
|
|
|
|
713
|
|
Total other income
(expense)
|
|
|
(52,900
|
)
|
|
|
(23,765
|
)
|
|
|
|
|
|
|
|
|
|
Income
(loss) before income taxes and minority interest
|
|
|
11,515
|
|
|
|
(17,523
|
)
|
Income
tax (expense)
benefit
|
|
|
(4,222
|
)
|
|
|
6,080
|
|
Minority
interest, net of
tax
|
|
|
(114
|
)
|
|
|
(867
|
)
|
|
|
|
|
|
|
|
|
|
NET
INCOME
(LOSS)
|
|
$
|
7,179
|
|
|
$
|
(12,310
|
)
|
|
|
|
|
|
|
|
|
|
Net
income (loss) per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.63
|
|
|
$
|
(1.09
|
)
|
Diluted
|
|
$
|
0.62
|
|
|
$
|
(1.09
|
)
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
11,387
|
|
|
|
11,290
|
|
Diluted
|
|
|
11,643
|
|
|
|
11,290
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON
WILLIAMS ENERGY
, INC.
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Total
|
|
|
|
Common
Stock
|
|
|
Additional
|
|
|
|
|
|
Compre-
|
|
|
Compre-
|
|
|
|
No.
of
|
|
|
Par
|
|
|
Paid-In
|
|
|
Retained
|
|
|
hensive
|
|
|
hensive
|
|
|
|
Shares
|
|
|
Value
|
|
|
Capital
|
|
|
Earnings
|
|
|
Income
|
|
|
Income
|
|
BALANCE,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2007
|
|
|
11,354
|
|
|
$
|
1,135
|
|
|
$
|
121,063
|
|
|
$
|
35,890
|
|
|
$
|
2,718
|
|
|
|
|
Net
income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7,179
|
|
|
|
-
|
|
|
$
|
7,179
|
|
Unrealized gain
on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
marketable
securities,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net of tax of
$231
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
429
|
|
|
|
429
|
|
Total
comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,608
|
|
Issuance of stock
through
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
plans
|
|
|
750
|
|
|
|
75
|
|
|
|
15,768
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
BALANCE,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2008
|
|
|
12,104
|
|
|
$
|
1,210
|
|
|
$
|
136,831
|
|
|
$
|
43,069
|
|
|
$
|
3,147
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON WILLIAMS
ENERGY, INC.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Unaudited)
(In
thousands)
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
7,179
|
|
|
$
|
(12,310
|
)
|
Adjustments to reconcile net
income (loss) to cash
|
|
|
|
|
|
|
|
|
provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
30,273
|
|
|
|
15,231
|
|
Impairment of property and
equipment
|
|
|
-
|
|
|
|
565
|
|
Exploration
costs
|
|
|
297
|
|
|
|
11,105
|
|
Gain on sales of property and
equipment,
net
|
|
|
(560
|
)
|
|
|
(128
|
)
|
Deferred income
taxes
|
|
|
4,100
|
|
|
|
(6,080
|
)
|
Non-cash employee
compensation
|
|
|
342
|
|
|
|
610
|
|
Unrealized loss on
derivatives
|
|
|
32,028
|
|
|
|
18,822
|
|
Settlements on derivatives with
financing elements
|
|
|
10,415
|
|
|
|
5,593
|
|
Amortization of debt issue
costs
|
|
|
346
|
|
|
|
309
|
|
Accretion of abandonment
obligations
|
|
|
530
|
|
|
|
618
|
|
Minority interest, net of
tax
|
|
|
114
|
|
|
|
867
|
|
|
|
|
|
|
|
|
|
|
Changes in operating working
capital:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(13,869
|
)
|
|
|
(286
|
)
|
Accounts
payable
|
|
|
11,985
|
|
|
|
(3,703
|
)
|
Other
|
|
|
(5,130
|
)
|
|
|
5,016
|
|
Net cash provided by operating
activities
|
|
|
78,050
|
|
|
|
36,229
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Additions to property and
equipment
|
|
|
(49,610
|
)
|
|
|
(55,749
|
)
|
Additions to equipment of
Larclay
JV.
|
|
|
(9
|
)
|
|
|
(19,316
|
)
|
Proceeds from sales of property
and
equipment
|
|
|
624
|
|
|
|
645
|
|
Change in equipment
inventory
|
|
|
(1,620
|
)
|
|
|
3,896
|
|
Other
|
|
|
69
|
|
|
|
(2,970
|
)
|
Net cash used in investing
activities
|
|
|
(50,546
|
)
|
|
|
(73,494
|
)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
Proceeds from long-term
debt
|
|
|
-
|
|
|
|
25,000
|
|
Proceeds from long-term debt of
Larclay
JV
|
|
|
-
|
|
|
|
8,727
|
|
Repayments of long-term
debt
|
|
|
(10,800
|
)
|
|
|
-
|
|
Repayments of long-term debt of
Larclay
JV
|
|
|
(6,562
|
)
|
|
|
-
|
|
Proceeds from exercise of stock
options
|
|
|
6,452
|
|
|
|
5,962
|
|
Settlements on derivatives with
financing
elements
|
|
|
(10,415
|
)
|
|
|
(5,593
|
)
|
Net cash provided by (used in)
financing activities
|
|
|
(21,325
|
)
|
|
|
34,096
|
|
|
|
|
|
|
|
|
|
|
NET
INCREASE (DECREASE) IN CASH AND
|
|
|
|
|
|
|
|
|
CASH
EQUIVALENTS
|
|
|
6,179
|
|
|
|
(3,169
|
)
|
|
|
|
|
|
|
|
|
|
CASH
AND CASH EQUIVALENTS
|
|
|
|
|
|
|
|
|
Beginning of
period
|
|
|
12,344
|
|
|
|
13,840
|
|
End of
period
|
|
$
|
18,523
|
|
|
$
|
10,671
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURES
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of
amounts
capitalized
|
|
$
|
11,628
|
|
|
$
|
11,739
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CLAYTON WILLIAMS
ENERGY, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
March
31, 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 24% 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 27% 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 12). The Company also accounts for its undivided interests
in oil and gas limited partnerships using the proportionate consolidation
method, whereby its share of assets, liabilities, revenues and expenses are
consolidated with other operations. All significant intercompany
transactions and balances associated with the consolidated operations have been
eliminated. Certain reclassifications of prior year financial
statement amounts have been made to conform to current year
presentations.
In the
opinion of management, the Company's unaudited consolidated financial statements
as of March 31, 2008 and for the interim periods ended March 31, 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 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 Financial Accounting Standards Board (“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:
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
7¾%
Senior Notes, due
2013
|
|
$
|
225,000
|
|
|
$
|
225,000
|
|
Secured
bank credit facility, due May
2009
|
|
|
155,000
|
|
|
|
165,800
|
|
Secured
term loan of Larclay JV, due June
2011
|
|
|
55,313
|
|
|
|
61,875
|
|
|
|
|
435,313
|
|
|
|
452,675
|
|
Less
current maturities
(a)
|
|
|
(20,625
|
)
|
|
|
(22,500
|
)
|
|
|
$
|
414,688
|
|
|
$
|
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 and 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 March
31, 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. At March 31, 2008, the borrowing base
established by the banks was $275 million, with no monthly commitment
reductions. After allowing for outstanding letters of credit totaling
$804,000, the Company had $119.2 million available under the credit
facility at March 31, 2008. Subsequent to March 31, 2008, the
borrowing base was reduced to $250 million after the sale of assets (see Note
14).
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 quarter ended March 31, 2008 was 5.6%.
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 March 31, 2008.
Secured Term Loan of Larclay
JV
In
connection with the Company’s investment in Larclay JV (see Note 12), 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 March 31, 2008, the effective
interest rate on the Larclay JV term loan was 6.9%.
5.
Other Non-Current Liabilities
Other
non-current liabilities consist of the following:
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Abandonment
obligations
|
|
$
|
31,237
|
|
|
$
|
30,994
|
|
Minority interest, net of
tax
|
|
|
5,000
|
|
|
|
4,886
|
|
Other taxes
payable
|
|
|
358
|
|
|
|
358
|
|
Other
|
|
|
776
|
|
|
|
808
|
|
|
|
$
|
37,371
|
|
|
$
|
37,046
|
|
Changes
in abandonment obligations for the three months ended March 31, 2008 and 2007
are as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Beginning of
period
|
|
$
|
30,994
|
|
|
$
|
27,846
|
|
Additional abandonment
obligations from new
wells
|
|
|
68
|
|
|
|
145
|
|
Sales of
properties
|
|
|
(355
|
)
|
|
|
(181
|
)
|
Accretion
expense
|
|
|
530
|
|
|
|
618
|
|
End of
period
|
|
$
|
31,237
|
|
|
$
|
28,428
|
|
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 March 31, 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
March 31, 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 March 31, 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 three months ended March 31, 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)
|
|
|
(750,000
|
)
|
|
$
|
21.00
|
|
|
|
|
|
|
|
Outstanding
at March 31, 2008
|
|
|
65,485
|
|
|
$
|
15.27
|
|
|
|
3.45
|
|
|
$
|
2,437,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested
at March 31, 2008
|
|
|
65,485
|
|
|
$
|
15.27
|
|
|
|
3.45
|
|
|
$
|
2,437,566
|
|
Exercisable
at March 31, 2008
|
|
|
65,485
|
|
|
$
|
15.27
|
|
|
|
3.45
|
|
|
$
|
2,437,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Based on closing
price at March 31, 2008 of $52.49 per share.
|
|
(b)
Cash received for options exercised totaled $15.8 million, of which
$9.3 million was received in April 2008.
|
|
The
following table summarizes information with respect to options outstanding at
March 31, 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
|
33,485
|
|
$
5.50
|
|
1.1
|
$10.00 -
$19.74
|
10,000
|
|
$
11.93
|
|
3.1
|
$22.90 -
$41.74
|
22,000
|
|
$
31.65
|
|
7.2
|
|
65,485
|
|
$
15.27
|
|
3.5
|
The
following table presents certain information regarding stock-based compensation
amounts for the three months ended March 31, 2008 and 2007.
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
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
|
|
$
|
19,650
|
|
|
$
|
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 $250,000 of non-cash compensation expense during the
three-month period ended March 31, 2008 and $500,000 for the three-month
period ended March 31, 2007 for the estimated fair value of the APO Arrangements
granted during those periods.
SWR Reward
Plan
In
January 2007, the Company granted awards under the Southwest Royalties Reward
Plan (the “SWR Reward Plan”), a one-time incentive plan designed to reward
eligible employees and other service providers for continued quality service to
the Company, and to encourage retention of those employees and service providers
by providing them the opportunity to receive bonus payments that are based on
certain profits derived from a portion of the Company’s working interest in the
RS Windham C3 well in Upton County, Texas. Eligible participants in
the SWR Reward Plan include those officers, key employees and consultants,
excluding Mr. Williams, who made significant contributions to the
acquisition and development of Southwest Royalties, Inc.
The SWR
Reward Plan provides for quarterly cash bonuses to the participants, as a group,
equal to the after-payout cash flow from a 22.5% working interest in the RS
Windham C3 well. 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. The
quarterly bonus amounts are allocated among the participants based on each
participant’s bonus percentage.
To
continue as a participant in the SWR Reward Plan, 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 SWR Reward plan, subject to certain restrictions. The
full vesting date may occur sooner than October 25, 2011 in the event of a
change of control or sale transaction, as defined in the SWR Reward
Plan.
The
Company recognizes compensation expense related to the SWR Reward Plan over the
vesting period. For the quarter ended March 31, 2008, the
Company recorded compensation expense of $16,479 for the SWR Reward
Plan. For the quarter ended March 31, 2007, the company recorded
$97,000 of compensation expense.
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 March 31,
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
nd
Quarter 2008
|
|
|
426,000
|
|
|
$
|
4.00
|
|
|
$
|
5.15
|
|
|
|
132,000
|
|
|
$
|
23.00
|
|
|
$
|
25.07
|
|
3
rd
Quarter 2008
|
|
|
419,000
|
|
|
$
|
4.00
|
|
|
$
|
5.15
|
|
|
|
128,000
|
|
|
$
|
23.00
|
|
|
$
|
25.07
|
|
|
|
|
845,000
|
|
|
|
|
|
|
|
|
|
|
|
260,000
|
|
|
|
|
|
|
|
|
|
Swaps:
|
|
Gas
|
|
|
Oil
|
|
|
|
MMBtu
(a)
|
|
|
Price
|
|
|
Bbls
|
|
|
Price
|
|
Production
Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
2
nd
Quarter 2008
|
|
|
4,650,000
|
|
|
$
|
9.20
|
|
|
|
330,000
|
|
|
$
|
79.84
|
|
3
rd
Quarter 2008
|
|
|
4,200,000
|
|
|
$
|
9.15
|
|
|
|
310,000
|
|
|
$
|
78.96
|
|
4
th
Quarter
2008
|
|
|
4,200,000
|
|
|
$
|
9.15
|
|
|
|
400,000
|
|
|
$
|
82.21
|
|
2009
|
|
|
3,600,000
|
|
|
$
|
9.33
|
|
|
|
1,440,000
|
|
|
$
|
85.30
|
|
|
|
|
16,650,000
|
|
|
|
|
|
|
|
2,480,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
One
MMBtu equals one Mcf at a Btu factor of 1,000.
|
|
In
September 2007, the Company terminated certain fixed-priced oil swaps covering
90,000 barrels at a price of $76.65 from April 2008 through December 2008,
resulting in an aggregate loss of approximately $995,000, which will be paid to
the counterparty monthly during 2008.
Interest Rate
Derivatives
At March
31, 2008, the Company was a party to two interest rate swaps. Under
these derivatives, the Company pays a fixed rate for the notional principal
balances and receives a floating market rate based on LIBOR. The
interest rate swaps are settled quarterly. The following summarizes
information concerning the Company’s net positions in open interest rate swaps
at March 31, 2008.
Interest
Rate Swaps:
|
|
|
|
|
Fixed
|
|
|
|
Principal
|
|
|
Libor
|
|
|
|
Balance
|
|
|
Rates
|
|
Period:
|
|
|
|
|
|
|
April 1, 2008 to September 24,
2008
(a)
|
|
$
|
100,000,000
|
|
|
|
4.73
|
%
|
April 1, 2008 to November 3,
2008
|
|
$
|
45,000,000
|
|
|
|
5.73
|
%
|
|
|
|
|
|
|
|
|
|
(a)
In
April 2008, the Company terminated this $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 three months ended March 31, 2008, the
Company reported a $46.1 million net loss on derivatives, consisting of a
$32 million loss related to changes in mark-to-market valuations and a $14.1
million realized loss for settled contracts. For the three months
ended March 31, 2007, the Company reported a $16.8 million loss on
derivatives, consisting of an $18.8 million loss related to changes in
mark-to-market valuations and a $2 million 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 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
March 31, 2008 and December 31, 2007 was approximately $194.6 million
and $196.9 million, respectively.
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 March 31, 2008 and December 31, 2007
are summarized below.
|
|
Fair
Value Measurements
|
|
|
|
March
31, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
securities
|
|
$
|
7,848
|
|
|
$
|
-
|
|
|
$
|
7,188
|
|
|
$
|
-
|
|
Total
assets
|
|
$
|
7,848
|
|
|
$
|
-
|
|
|
$
|
7,188
|
|
|
$
|
-
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives,
net
|
|
$
|
-
|
|
|
$
|
79,550
|
|
|
$
|
-
|
|
|
$
|
48,696
|
|
Interest derivatives,
net
|
|
|
-
|
|
|
|
2,216
|
|
|
|
-
|
|
|
|
1,044
|
|
Total
liabilities
|
|
$
|
-
|
|
|
$
|
81,766
|
|
|
$
|
-
|
|
|
$
|
49,740
|
|
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 March 31,
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. Assets
Held For Sale
Included
in assets held for sale is $72.1 million at March 31, 2008 and $17.3 million at
December 31, 2007 that the Company has designated as held for sale assets under
SFAS 144. The December 31, 2007 balance consisted of $15.8 million
for the estimated fair value of two 2,000 horsepower drilling rigs and related
components and $1.5 million for well service equipment. At March 31,
2008, assets held for sale consisted of $16 million for the estimated fair value
of two 2,000 horsepower drilling rigs and related components, $1.6 million for
well service equipment and $54.5 million related to the net book value of
certain oil and gas properties in South Louisiana that the Company offered for
sale (see Note 14).
11.
Income Taxes
The
Company’s effective federal and state income tax rate for the three months ended
March 31, 2008 of 36.7% differed from the statutory federal rate of 35% due to
tax benefits derived from 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. As a general rule, 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 March 31, 2008 and
December 31, 2007 is as follows:
|
|
March
31,
|
|
|
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 three 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 March 31,
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.
The tax
liability 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.
12. 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). Pursuant to the requirements of the joint venture
agreements, the Company has made two loans to Larclay JV, one in November 2007
for $4.6 million to finance excess construction costs and one in April 2008 for
$2.5 million to finance its 50% share of a working capital assessment required
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 note.
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
$68.7 million at March 31, 2008. The Company did not pay any
idle rig fees during the three months ended March 31, 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 March 31, 2008, Lariat’s equity ownership
in the net assets of Larclay JV was $5 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 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 March 31, 2008 is $7.8 million and is
recorded in other non-current assets, based on the closing price of the stock as
of March 31, 2008. The change in fair market value during the three
months ended March 31, 2008 of $660,000, net of tax of $231,000, was recorded in
accumulated other comprehensive income.
13. Oil
and Gas Properties
The following sets forth the capitalized costs for oil and gas properties as of
March 31, 2008 and December 31, 2007.
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$
|
1,179,636
|
|
|
$
|
1,258,166
|
|
Unproved
properties
|
|
|
134,150
|
|
|
|
115,924
|
|
Total capitalized
costs
|
|
|
1,313,786
|
|
|
|
1,374,090
|
|
Accumulated depreciation,
depletion and amortization
|
|
|
(695,162
|
)
|
|
|
(727,739
|
)
|
Net capitalized
costs
|
|
$
|
618,624
|
|
|
$
|
646,351
|
|
14.
Subsequent Event
In April
2008, the Company and its affiliates sold all of their interests in 16 producing
wells for approximately $88.6 million, net of customary closing
adjustments. The Company expects to record a gain of approximately
$33 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. The Company will record a gain
of approximately $300,000 on the sale of this asset in the second quarter of
2008.
15.
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 periods ended March 31, 2008 and
2007.
For
the Three Months Ended
|
|
|
|
|
Contract
|
|
|
Intercompany
|
|
|
Consolidated
|
|
March
31, 2008
|
|
Oil
and Gas
|
|
|
Drilling
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In
thousands)
|
|
Revenues
|
|
$
|
122,026
|
|
|
$
|
17,163
|
|
|
$
|
(2,331
|
)
|
|
$
|
136,858
|
|
Depreciation,
depletion and amortization (a)
|
|
|
27,988
|
|
|
|
2,610
|
|
|
|
(325
|
)
|
|
|
30,273
|
|
Other
operating expenses (b)
|
|
|
30,815
|
|
|
|
13,008
|
|
|
|
(1,653
|
)
|
|
|
42,170
|
|
Interest
expense
|
|
|
6,352
|
|
|
|
1,094
|
|
|
|
-
|
|
|
|
7,446
|
|
Other
(income) expense
|
|
|
45,454
|
|
|
|
-
|
|
|
|
-
|
|
|
|
45,454
|
|
Income
before income taxes and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
minority
interest
|
|
|
11,417
|
|
|
|
451
|
|
|
|
(353
|
)
|
|
|
11,515
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax (expense) benefit
|
|
|
(3,964
|
)
|
|
|
(258
|
)
|
|
|
-
|
|
|
|
(4,222
|
)
|
Minority
interest, net of tax
|
|
|
62
|
|
|
|
(176
|
)
|
|
|
-
|
|
|
|
(114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
7,515
|
|
|
$
|
17
|
|
|
$
|
(353
|
)
|
|
$
|
7,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$
|
816,632
|
|
|
$
|
96,197
|
|
|
$
|
(4,787
|
)
|
|
$
|
908,042
|
|
Additions
to property and equipment
|
|
$
|
55,431
|
|
|
$
|
9
|
|
|
$
|
(353
|
)
|
|
$
|
55,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended
|
|
|
|
|
Contract
|
|
|
Intercompany
|
|
|
Consolidated
|
|
March
31, 2007
|
|
Oil
and Gas
|
|
|
Drilling
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In
thousands)
|
|
Revenues
|
|
$
|
64,093
|
|
|
$
|
10,936
|
|
|
$
|
(2,519
|
)
|
|
$
|
72,510
|
|
Depreciation,
depletion and amortization (a)
|
|
|
14,413
|
|
|
|
1,607
|
|
|
|
(224
|
)
|
|
|
15,796
|
|
Other
operating expenses (b)
|
|
|
45,507
|
|
|
|
5,827
|
|
|
|
(862
|
)
|
|
|
50,472
|
|
Interest
expense
|
|
|
6,795
|
|
|
|
834
|
|
|
|
-
|
|
|
|
7,629
|
|
Other
(income) expense
|
|
|
16,136
|
|
|
|
-
|
|
|
|
-
|
|
|
|
16,136
|
|
Income
before income taxes and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
minority
interest
|
|
|
(18,758
|
)
|
|
|
2,668
|
|
|
|
(1,433
|
)
|
|
|
(17,523
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax (expense) benefit
|
|
|
7,014
|
|
|
|
(934
|
)
|
|
|
-
|
|
|
|
6,080
|
|
Minority
interest, net of tax
|
|
|
-
|
|
|
|
(867
|
)
|
|
|
-
|
|
|
|
(867
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
(11,744
|
)
|
|
$
|
867
|
|
|
$
|
(1,433
|
)
|
|
$
|
(12,310
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$
|
730,651
|
|
|
$
|
92,350
|
|
|
$
|
(3,931
|
)
|
|
$
|
819,070
|
|
Additions
to property and equipment
|
|
$
|
72,776
|
|
|
$
|
5,765
|
|
|
$
|
(1,433
|
)
|
|
$
|
77,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
16.
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 16 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
March
31, 2008
(Dollars
in thousands)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Current
assets
|
|
$
|
195,784
|
|
|
$
|
114,244
|
|
|
$
|
19,463
|
|
|
$
|
(139,933
|
)
|
|
$
|
189,558
|
|
Property
and equipment, net
|
|
|
335,417
|
|
|
|
281,811
|
|
|
|
83,510
|
|
|
|
-
|
|
|
|
700,738
|
|
Investments
in subsidiaries
|
|
|
81,954
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(81,954
|
)
|
|
|
-
|
|
Other
assets
|
|
|
21,733
|
|
|
|
336
|
|
|
|
277
|
|
|
|
(4,600
|
)
|
|
|
17,746
|
|
Total
assets
|
|
$
|
634,888
|
|
|
$
|
396,391
|
|
|
$
|
103,250
|
|
|
$
|
(226,487
|
)
|
|
$
|
908,042
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
139,145
|
|
|
$
|
171,469
|
|
|
$
|
42,220
|
|
|
$
|
(139,933
|
)
|
|
$
|
212,901
|
|
Non-current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
380,000
|
|
|
|
-
|
|
|
|
39,288
|
|
|
|
(4,600
|
)
|
|
|
414,688
|
|
Fair
value of derivatives
|
|
|
10,192
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,192
|
|
Other
|
|
|
29,368
|
|
|
|
56,523
|
|
|
|
113
|
|
|
|
-
|
|
|
|
86,004
|
|
|
|
|
419,560
|
|
|
|
56,523
|
|
|
|
39,401
|
|
|
|
(4,600
|
)
|
|
|
510,884
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity
|
|
|
76,183
|
|
|
|
168,399
|
|
|
|
21,629
|
|
|
|
(81,954
|
)
|
|
|
184,257
|
|
Total
liabilities and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stockholders’
equity
|
|
$
|
634,888
|
|
|
$
|
396,391
|
|
|
$
|
103,250
|
|
|
$
|
(226,487
|
)
|
|
$
|
908,042
|
|
Condensed
Consolidating Balance Sheet
March
31, 2007
(Dollars
in thousands)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Current
assets
|
|
$
|
134,991
|
|
|
$
|
97,845
|
|
|
$
|
12,603
|
|
|
$
|
(146,335
|
)
|
|
$
|
99,104
|
|
Property
and equipment, net
|
|
|
329,066
|
|
|
|
279,449
|
|
|
|
85,760
|
|
|
|
-
|
|
|
|
694,275
|
|
Investments
in subsidiaries
|
|
|
71,445
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(71,445
|
)
|
|
|
-
|
|
Other
assets
|
|
|
24,756
|
|
|
|
326
|
|
|
|
609
|
|
|
|
-
|
|
|
|
25,691
|
|
Total
assets
|
|
$
|
560,258
|
|
|
$
|
377,620
|
|
|
$
|
98,972
|
|
|
$
|
(217,780
|
)
|
|
$
|
819,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
90,857
|
|
|
$
|
178,423
|
|
|
$
|
31,772
|
|
|
$
|
(146,335
|
)
|
|
$
|
154,717
|
|
Non-current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
390,000
|
|
|
|
-
|
|
|
|
55,313
|
|
|
|
-
|
|
|
|
445,313
|
|
Fair
value of derivatives
|
|
|
3,423
|
|
|
|
15,290
|
|
|
|
-
|
|
|
|
-
|
|
|
|
18,713
|
|
Other
|
|
|
5,142
|
|
|
|
56,337
|
|
|
|
106
|
|
|
|
-
|
|
|
|
61,585
|
|
|
|
|
398,565
|
|
|
|
71,627
|
|
|
|
55,419
|
|
|
|
-
|
|
|
|
525,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity
|
|
|
70,836
|
|
|
|
127,570
|
|
|
|
11,781
|
|
|
|
(71,445
|
)
|
|
|
138,742
|
|
Total
liabilities and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stockholders’
equity
|
|
$
|
560,258
|
|
|
$
|
377,620
|
|
|
$
|
98,972
|
|
|
$
|
(217,780
|
)
|
|
$
|
819,070
|
|
Condensed
Consolidating Statement of Operations
Three
Months Ended March 31, 2008
(Dollars
in thousands)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Total
revenue
|
|
$
|
80,232
|
|
|
$
|
41,973
|
|
|
$
|
17,363
|
|
|
$
|
(2,710
|
)
|
|
$
|
136,858
|
|
Costs
and
expenses
|
|
|
39,871
|
|
|
|
19,128
|
|
|
|
15,801
|
|
|
|
(2,357
|
)
|
|
|
72,443
|
|
Operating
income (loss)
|
|
|
40,361
|
|
|
|
22,845
|
|
|
|
1,562
|
|
|
|
(353
|
)
|
|
|
64,415
|
|
Other
income (expense)
|
|
|
(48,269
|
)
|
|
|
(3,578
|
)
|
|
|
(1,053
|
)
|
|
|
-
|
|
|
|
(52,900
|
)
|
Income
tax
benefit
|
|
|
(4,222
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,222
|
)
|
Minority
interest, net of tax
|
|
|
(114
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(loss)
|
|
$
|
(12,244
|
)
|
|
$
|
19,267
|
|
|
$
|
509
|
|
|
$
|
(353
|
)
|
|
$
|
7,179
|
|
Condensed
Consolidating Statement of Operations
Three
Months Ended March 31, 2007
(Dollars
in thousands)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Total
revenue
|
|
$
|
40,136
|
|
|
$
|
24,169
|
|
|
$
|
11,038
|
|
|
$
|
(2,833
|
)
|
|
$
|
72,510
|
|
Costs
and
expenses
|
|
|
44,902
|
|
|
|
16,139
|
|
|
|
7,575
|
|
|
|
(2,348
|
)
|
|
|
66,268
|
|
Operating
income (loss)
|
|
|
(4,766
|
)
|
|
|
8,030
|
|
|
|
3,463
|
|
|
|
(485
|
)
|
|
|
6,242
|
|
Other
income (expense)
|
|
|
(19,557
|
)
|
|
|
(3,402
|
)
|
|
|
(806
|
)
|
|
|
-
|
|
|
|
(23,765
|
)
|
Income
tax
benefit
|
|
|
6,080
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6,080
|
|
Minority
interest, net of tax
|
|
|
(867
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(867
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(loss)
|
|
$
|
(19,110
|
)
|
|
$
|
4,628
|
|
|
$
|
2,657
|
|
|
$
|
(485
|
)
|
|
$
|
(12,310
|
)
|
Condensed
Consolidating Statement of Cash Flows
Three
Months Ended March 31, 2008
(Dollars
in thousands)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Operating
activities
|
|
$
|
41,156
|
|
|
$
|
31,955
|
|
|
$
|
4,614
|
|
|
$
|
325
|
|
|
$
|
78,050
|
|
Investing
activities
|
|
|
(36,008
|
)
|
|
|
(14,032
|
)
|
|
|
(181
|
)
|
|
|
(325
|
)
|
|
|
(50,546
|
)
|
Financing
activities
|
|
|
3,172
|
|
|
|
(17,923
|
)
|
|
|
(6,574
|
)
|
|
|
-
|
|
|
|
(21,325
|
)
|
Net
increase (decrease) in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
and cash equivalents
|
|
|
8,320
|
|
|
|
-
|
|
|
|
(2,141
|
)
|
|
|
-
|
|
|
|
6,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
at the beginning of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
the
period
|
|
|
5,325
|
|
|
|
1,288
|
|
|
|
5,731
|
|
|
|
-
|
|
|
|
12,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
at end of the period
|
|
$
|
13,645
|
|
|
$
|
1,288
|
|
|
$
|
3,590
|
|
|
$
|
-
|
|
|
$
|
18,523
|
|
Condensed
Consolidating Statement of Cash Flows
Three
Months Ended March 31, 2007
(Dollars
in thousands)
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Adjustments/
|
|
|
|
|
|
|
Issuer
|
|
|
Subsidiaries
|
|
|
Entities
|
|
|
Eliminations
|
|
|
Consolidated
|
|
Operating
activities
|
|
$
|
8,042
|
|
|
$
|
13,657
|
|
|
$
|
14,306
|
|
|
$
|
224
|
|
|
$
|
36,229
|
|
Investing
activities
|
|
|
19,114
|
|
|
|
(5,460
|
)
|
|
|
(87,424
|
)
|
|
|
276
|
|
|
|
(73,494
|
)
|
Financing
activities
|
|
|
(32,185
|
)
|
|
|
(8,346
|
)
|
|
|
75,127
|
|
|
|
(500
|
)
|
|
|
34,096
|
|
Net
increase (decrease) in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
and cash equivalents
|
|
|
(5,029
|
)
|
|
|
(149
|
)
|
|
|
2,009
|
|
|
|
-
|
|
|
|
(3,169
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
at the beginning of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
the
period
|
|
|
12,542
|
|
|
|
1,298
|
|
|
|
-
|
|
|
|
-
|
|
|
|
13,840
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
at end of the period
|
|
$
|
7,513
|
|
|
$
|
1,149
|
|
|
$
|
2,009
|
|
|
$
|
-
|
|
|
$
|
10,671
|
|
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.
Overview
We are an
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 quarter of 2007 to the first quarter of 2008. Approximately 68%
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 first quarter of 2008
and the outlook for the remainder of 2008.
·
|
Our
oil and gas sales increased $57.7 million, or 94%, from 2007, of which
price variances accounted 70% of the increase and incremental production
accounted for the remaining 30%.
|
·
|
Our
oil and gas production for the first quarter of 2008 was 27% higher on an
Mcfe basis than in the comparable period in 2007 resulting primarily from
drilling programs in all of our core areas of
operations.
|
·
|
We
recorded a $46.1 million net loss on derivatives in the first quarter
of 2008. We recorded a $14.1 million realized loss on
settled contracts and a $32 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
the first quarter of 2008, we decreased borrowings under our revolving
credit facility by $10.8 million from $165.8 million at December
31, 2007 to $155 million at March 31, 2008. Subsequent to March
31, 2008, we further reduced our debt using proceeds from the sale of
assets in South Louisiana.
|
·
|
At
March 31, 2008, our capitalized unproved oil and gas properties totaled
$134.2 million, of which approximately $80.3 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 at record-high 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 shown
in “Liquidity and Capital Resources – Capital Expenditures,” we incurred
expenditures for exploration and development activities of $57.7 million during
the first three months of 2008, of which approximately 21% were related to
exploratory drilling and leasing activities. We also increased our
estimates for capital expenditures in fiscal 2008 from $256.5 million to
$344.5 million. The increase in capital spending relates
primarily to developmental activities in the Permian Basin and North
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
$21.5 million in the Permian Basin during the first quarter of 2008 on
exploration and development activities, of which $15.4 million was spent on
drilling and completion activities and $6.1 million was spent on seismic and
leasing activities. We drilled 4 gross (4.0 net) operated wells
in the Permian Basin and conducted remedial operations on existing wells in
2008.
The
Permian Basin continues to be a significant source of cash flow for
us. We currently expect to spend $168 million on development
activities in the Permian Basin in 2008. Most of the drilling
activities relate to our War-Wink and Amacker-Tippett prospects in West Texas,
and to a lesser extent our acreage positions in Andrews and Crockett Counties,
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 Crockett County 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
historic highs, 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 $10.8 million during the first quarter of 2008 and
currently plan to spend $55.4 million on development activities and leasing in
this area during fiscal 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
$14.8 million in North Louisiana during the first three months of 2008 on
exploration and development activities, of which $13.5 million was spent on
drilling and completion activities and $1.3 million was spent on seismic
and leasing activities. We currently plan to spend approximately
$62.6 million in North Louisiana in 2008.
To date,
we have completed thirteen wells on our Terryville prospect as
producers. These wells are currently producing at combined rates of
approximately 9,300 Mcf of gas per day and 200 barrels of oil per day, net to
our interest. We plan to drill three additional development wells on
this prospect during the remainder of 2008. We have also completed
one well as a producer in our Ruston prospect and plan to drill three 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 currently plan to drill an offset
to this well in the third quarter of 2008.
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
$2.8 million in South Louisiana during the first three months 2008 on
exploration and development activities, of which $2.1 million was spent on
drilling and completion activities and $700,000 was spent on seismic and leasing
activities. We currently plan to spend approximately $18.7 million in
South Louisiana in 2008 for drilling and leasing activities.
In late
2007, we entered into an agreement with an industry partner, in 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. We expect to spend approximately $2.9
million for our portion of drilling activities under this
agreement.
In April
2008, we sold all of our interests in 16 producing wells in South Louisiana to
an industry partner for approximately $88.6 million, net of customary closing
adjustments, and expect to record a gain of approximately $33 million in the
second quarter of 2008 in connection with this transaction.
We
currently plan to spend $15.8 million in South Louisiana in 2008 to
generate and lease new exploratory prospects and to drill wells on existing
exploratory and developmental prospects not related to the five-well agreement
described above.
East
Texas Bossier
We
currently have approximately 142,000 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 attempting to complete these
wells. 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 outcome of those wells.
We
currently plan to spend approximately $28.6 million in the East Texas Bossier
area for leasing and seismic activities and to drill one well on our Jewett
prospect. Despite the disappointing results of the Big Bill Simpson
#1 and the Margarita #1, we are optimistic that our acreage position in this
area is prospective for potentially significant deep Bossier
discoveries. As more wells are drilled and more subsurface control
data is obtained, we believe our prospects for discoveries
improve. We have begun a 3-D seismic shoot in Leon County, Texas over
the Big Bill Simpson prospect in an attempt to high grade our next well’s
position on this acreage. In addition, we are considering a
proprietary 3-D shoot in Burleson County, Texas to help us select potential
drill sites on other deep Bossier prospects in this area.
Other
In Utah,
we plan to participate in the drilling of a 12,000-foot exploratory well, the
Lamb #1 in the Overthrust prospect (33% working interest) in Sanpete County,
Utah. The well will target the oil-prone Navajo sandstone
formation.
Supplemental
Information
The
following unaudited information is intended to supplement the consolidated
financial statements included in this Form 10-Q with data that is not readily
available from those statements.
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
Oil
and Gas Production Data:
|
|
|
|
|
|
|
Gas
(MMcf)
|
|
|
5,548
|
|
|
|
4,327
|
|
Oil
(MBbls)
|
|
|
684
|
|
|
|
543
|
|
Natural gas liquids
(MBbls)
|
|
|
58
|
|
|
|
46
|
|
Total
(MMcfe)
|
|
|
10,000
|
|
|
|
7,861
|
|
|
|
|
|
|
|
|
|
|
Average
Realized Prices
(a)
:
|
|
|
|
|
|
|
|
|
Gas
($/Mcf)
|
|
$
|
8.86
|
|
|
$
|
6.91
|
|
Oil
($/Bbl)
|
|
$
|
96.37
|
|
|
$
|
55.21
|
|
Natural gas liquids
($/Bbl)
|
|
$
|
54.83
|
|
|
$
|
33.30
|
|
|
|
|
|
|
|
|
|
|
Gain
(Losses) on Settled Derivative Contracts
(a)
:
|
|
|
|
|
|
|
|
|
($ in thousands, except per
unit)
|
|
|
|
|
|
|
|
|
Gas: Net realized
gain (loss)
|
|
$
|
(884
|
)
|
|
$
|
4,509
|
|
Per unit produced
($/Mcf)
|
|
$
|
(0.16
|
)
|
|
$
|
1.04
|
|
Oil: Net
realized loss
|
|
$
|
(12,906
|
)
|
|
$
|
(2,559
|
)
|
Per unit produced
($/Bbl)
|
|
$
|
(18.87
|
)
|
|
$
|
(4.71
|
)
|
|
|
|
|
|
|
|
|
|
Average
Daily Production:
|
|
|
|
|
|
|
|
|
Natural Gas
(Mcf):
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
|
15,562
|
|
|
|
15,389
|
|
North
Louisiana
|
|
|
13,596
|
|
|
|
2,409
|
|
South
Louisiana
|
|
|
23,552
|
|
|
|
20,121
|
|
Austin Chalk
(Trend)
|
|
|
2,460
|
|
|
|
2,011
|
|
Cotton Valley Reef
Complex
|
|
|
5,270
|
|
|
|
7,697
|
|
Other
|
|
|
527
|
|
|
|
451
|
|
Total
|
|
|
60,967
|
|
|
|
48,078
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls):
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
|
3,494
|
|
|
|
3,096
|
|
North
Louisiana
|
|
|
343
|
|
|
|
29
|
|
South
Louisiana
|
|
|
985
|
|
|
|
1,172
|
|
Austin Chalk
(Trend)
|
|
|
2,635
|
|
|
|
1,672
|
|
Other
|
|
|
59
|
|
|
|
64
|
|
Total
|
|
|
7,516
|
|
|
|
6,033
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
(Bbls):
|
|
|
|
|
|
|
|
|
Permian
Basin
|
|
|
215
|
|
|
|
199
|
|
Austin Chalk
(Trend)
|
|
|
272
|
|
|
|
265
|
|
Other
|
|
|
150
|
|
|
|
47
|
|
Total
|
|
|
637
|
|
|
|
511
|
|
(Continued)
|
|
Three
Months Ended
|
|
|
March
31,
|
|
|
2008
|
|
|
2007
|
Exploration
Costs (in thousands):
|
|
|
|
|
|
Abandonment and impairment
costs:
|
|
|
|
|
|
North
Louisiana
|
|
$
|
297
|
|
|
$
|
306
|
|
South
Louisiana
|
|
|
-
|
|
|
|
7,179
|
|
Permian
Basin
|
|
|
-
|
|
|
|
43
|
|
Utah
|
|
|
-
|
|
|
|
3,577
|
|
Total
|
|
|
297
|
|
|
|
11,105
|
|
|
|
|
|
|
|
|
|
|
Seismic and
other
|
|
|
3,675
|
|
|
|
890
|
|
Total exploration
costs
|
|
$
|
3,972
|
|
|
$
|
11,995
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
Depletion and Amortization (in thousands):
|
|
|
|
|
|
|
|
|
Oil and gas
depletion
|
|
$
|
27,741
|
|
|
$
|
13,548
|
|
Contract drilling
depreciation
|
|
|
2,285
|
|
|
|
1,383
|
|
Other
depreciation
|
|
|
247
|
|
|
|
300
|
|
Total
DD&A
|
|
$
|
30,273
|
|
|
$
|
15,231
|
|
|
|
|
|
|
|
|
|
|
Oil
and Gas Costs ($/Mcfe Produced):
|
|
|
|
|
|
|
|
|
Production
costs
|
|
$
|
2.06
|
|
|
$
|
2.20
|
|
Oil and gas
depletion
|
|
$
|
2.77
|
|
|
$
|
1.72
|
|
|
|
|
|
|
|
|
|
|
Net
Wells Drilled
(b)
:
|
|
|
|
|
|
|
|
|
Exploratory
Wells
|
|
|
1.7
|
|
|
|
5.0
|
|
Developmental
Wells
|
|
|
12.9
|
|
|
|
3.5
|
|
|
|
|
|
|
|
|
|
|
(a)
No derivatives 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
March 31, 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 $57.7 million, or 94%, from 2007, of
which price variances accounted for a $40.5 million increase and production
variances accounted for a $17.2 million increase. Production in 2008
(on an Mcfe basis) was 27% higher than 2007. Oil production increased
26% and gas production increased 28% in 2008 from 2007 due primarily to
incremental production attributable to drilling activity in North and South
Louisiana, the Permian Basin and Austin Chalk (Trend). In 2008, our
realized oil price was 75% higher than 2007, while our realized gas price was
28% 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 19% in 2008 as compared to 2007
due primarily to higher production tax costs related to higher commodity
prices. In addition, a combination of factors including increased oil
and gas production, rising oilfield service costs, and higher repair and
maintenance costs contributed to 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 27% increase in oil and
gas production on an Mcfe basis, production costs per Mcfe decreased 6% from
$2.20 per Mcfe in 2007 to $2.06 per Mcfe in 2008.
Oil and gas depletion expense increased $14.2 million from 2007 to 2008, of
which production variances accounted for a $3.7 million increase and rate
variances accounted for a $10.5 million increase. On an Mcfe
basis, depletion expense increased 61% from $1.72 per Mcfe in 2007 to $2.77 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 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 $297,000 of
exploration costs, as compared to $11.1 million in 2007. All of
the 2008 costs were incurred in Louisiana.
At March 31, 2008, our capitalized unproved oil and gas properties totaled
$134.2 million, of which approximately $80.3 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 $344.5 million on exploration and
development activities in 2008, of which approximately 32% 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 March 31, 2008, we included
contract drilling revenues of $14.8 million, other operating expenses of $11.4
million, depreciation expense of $2.3 million and interest expense of $1.1
million in our statement of operations (see Note 15 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 decreased 12% from
$3.9 million in 2007 to $3.4 million in 2008. Excluding
non-cash employee compensation, G&A expenses decreased from
$3.3 million in 2007 to $3.1 million in 2008 due primarily to a
decrease in professional fees. In 2008, we recorded a $250,000
non-cash compensation charge related to our after payout incentive plan and
$92,000 for stock-based employee compensation. In 2007, we recorded a
$500,000 non-cash compensation charge related to our after payout incentive plan
and $110,000 for stock-based employee compensation.
Interest
expense
Interest expense decreased 2% from $7.6 million in 2007 to
$7.4 million in 2008 due to a combination of factors. In 2007
and 2008, we used our revolving loan facility to partially finance our
exploration and development activities. The average daily principal
balance outstanding under our revolving credit facility for 2008 was
$174.5 million compared to $159.1 million for 2007 resulting in an
increase in interest expense of approximately $300,000 which was offset by an
$800,000 decrease in interest due to lower interest
rates. Capitalized interest for 2008 was $793,000 compared to
$973,000 in 2007. We also included $1.1 million of interest
expense associated with our Larclay JV during 2008 compared to $834,000 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 March 31, 2008, we reported a $46.1 million net loss on
derivatives, consisting of a $32 million non-cash loss to mark our
derivative positions to their fair value at March 31, 2008 and a
$14.1 million realized loss on settled contracts. For the three
months ended March 31, 2007, we reported a $16.8 million net loss on
derivatives, consisting of an $18.8 million non-cash loss to mark our
derivative positions to their fair value at March 31, 2007 and a $2 million
realized gain on settled contracts.
Loss
on sales of property and equipment
Loss on
sales of property and equipment for 2008 was $9,000 compared to $9.3 million in
2007. We recorded 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 March 31, 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 36.7% 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 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. However, we relied on
advances under the revolving credit facility to finance a portion of our
exploration and development activities in 2007 and the first quarter of
2008. At March 31, 2008, we had $155 million outstanding on the
revolving credit facility. Subsequent to March 31, 2008, we
reduced our revolving credit facility to approximately $60 million with proceeds
from the sales of assets.
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 $57.7
million during the first three months of 2008 and have increased our estimates
for planned expenditures for fiscal 2008 from $256.5 million to
$344.5 million. The following table summarizes, by area, our
actual expenditures for exploration and development activities for the first
quarter of 2008 and our planned expenditures for the year ending December 31,
2008.
|
|
Actual
|
|
|
Planned
|
|
|
|
|
|
|
Expenditures
|
|
|
Expenditures
|
|
|
Year
2008
|
|
|
|
Three
Months Ended
|
|
|
Year
Ending
|
|
|
Percentage
|
|
|
|
March
31, 2008
|
|
|
December
31, 2008
|
|
|
of
Total
|
|
|
|
(In
thousands)
|
|
|
|
|
Permian
Basin
|
|
$
|
21,500
|
|
|
$
|
168,000
|
|
|
|
49
|
%
|
North
Louisiana
|
|
|
14,800
|
|
|
|
62,600
|
|
|
|
18
|
%
|
Austin
Chalk
(Trend)
|
|
|
10,800
|
|
|
|
55,400
|
|
|
|
16
|
%
|
East
Texas
Bossier
|
|
|
6,900
|
|
|
|
28,600
|
|
|
|
8
|
%
|
South
Louisiana
|
|
|
2,700
|
|
|
|
18,700
|
|
|
|
6
|
%
|
Utah/California
|
|
|
900
|
|
|
|
10,900
|
|
|
|
3
|
%
|
Other
|
|
|
100
|
|
|
|
300
|
|
|
|
-
|
|
|
|
$
|
57,700
|
|
|
$
|
344,500
|
|
|
|
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 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
32% 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 three months
ended March 31, 2008 totaled $57.7 million, of which approximately 21% was on
exploratory prospects. We currently plan to spend approximately
$344.5 million for the calendar year 2008, of which approximately 32% 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. 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 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 three months ended March 31, 2008
increased $41.8 million, or 115%, as compared to the corresponding period
in 2007. Approximately $2.4 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 expense.
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 three months in 2008, we repaid $10.8 million on the revolving credit
facility from excess cash flow from operating activities. At March
31, 2008, we had a borrowing base of $275 million, leaving
$119.2 million available under the revolving loan facility after accounting
for outstanding letters of credit of $804,000. Subsequent to March
31, 2008, the borrowing base was reduced to $250 million after the sale of
assets.
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 reported working capital deficit decreased from
$76.4 million at December 31, 2007 to $23.3 million at March 31,
2008 due primarily to a combination of factors, including an increase in assets
held for sale, decreases in inventory 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 $190.4 million at March 31, 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 March 31, 2008 and December 31, 2007.
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Working
capital (deficit) per GAAP
|
|
$
|
(23,343
|
)
|
|
$
|
(76,388
|
)
|
Add
funds available under the revolving credit facility
|
|
|
119,196
|
|
|
|
108,396
|
|
Exclude
fair value of derivatives classified as current assets or current
liabilities
|
|
|
71,646
|
|
|
|
49,738
|
|
Exclude
current assets and current liabilities of Larclay JV
|
|
|
22,889
|
|
|
|
21,423
|
|
Working
capital per loan covenant
|
|
$
|
190,388
|
|
|
$
|
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 March 31, 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 November 2007 borrowing base
review resulted in maintaining the borrowing base at
$275 million. 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 quarter of
2008. At March 31, 2008, we had $155 million outstanding on the
revolving credit facility. Subsequent to March 31, 2008, the
borrowing base was reduced to $250 million after the sale of
assets.
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 and 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 March 31, 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
-
Quantitative 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 March 31, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
nd
Quarter 2008
|
|
|
426,000
|
|
|
$
|
4.00
|
|
|
$
|
5.15
|
|
|
|
132,000
|
|
|
$
|
23.00
|
|
|
$
|
25.07
|
|
3
rd
Quarter 2008
|
|
|
419,000
|
|
|
$
|
4.00
|
|
|
$
|
5.15
|
|
|
|
128,000
|
|
|
$
|
23.00
|
|
|
$
|
25.07
|
|
|
|
|
845,000
|
|
|
|
|
|
|
|
|
|
|
|
260,000
|
|
|
|
|
|
|
|
|
|
Swaps:
|
|
Gas
|
|
|
Oil
|
|
|
|
MMBtu
(a)
|
|
|
Price
|
|
|
Bbls
|
|
|
Price
|
|
Production
Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
2
nd
Quarter 2008
|
|
|
4,650,000
|
|
|
$
|
9.20
|
|
|
|
330,000
|
|
|
$
|
79.84
|
|
3
rd
Quarter 2008
|
|
|
4,200,000
|
|
|
$
|
9.15
|
|
|
|
310,000
|
|
|
$
|
78.96
|
|
4
th
Quarter 2008
|
|
|
4,200,000
|
|
|
$
|
9.15
|
|
|
|
400,000
|
|
|
$
|
82.21
|
|
2009
|
|
|
3,600,000
|
|
|
$
|
9.33
|
|
|
|
1,440,000
|
|
|
$
|
85.30
|
|
|
|
|
16,650,000
|
|
|
|
|
|
|
|
2,480,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
One
MMBtu equals one Mcf at a Btu factor of 1,000.
|
|
In
September 2007, the Company terminated certain fixed-priced oil swaps covering
90,000 barrels at a price of $76.65 from April 2008 through December 2008,
resulting in an aggregate loss of approximately $995,000, which will be paid to
the counterparty monthly during 2008.
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 $10.5 million.
Interest
Rates
We
are exposed to interest rate risk on our long-term debt with a variable interest
rate. At March 31, 2008, our variable rate debt had a carrying value
of $155 million, which approximated its fair value. At March 31,
2008, our fixed rate debt had a carrying value of $225 million and an
approximate fair value of $194.6 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 $7.9 million. Based on our
outstanding variable rate indebtedness at March 31, 2008 of $155 million, a
change in interest rates of 100 basis points would affect annual interest
payments by approximately $1.6 million.
We were a
party to two interest rate swaps. Under these derivatives, we pay a
fixed rate for the notional principal balances and receive a floating market
rate based on LIBOR. The interest rate swaps are settled
quarterly. The following summarizes information concerning our net
positions in open interest rate swaps at March 31, 2008.
Interest
Rate Swaps:
|
|
|
|
|
Fixed
|
|
|
|
Principal
|
|
|
Libor
|
|
|
|
Balance
|
|
|
Rates
|
|
Period:
|
|
|
|
|
|
|
April 1, 2008 to September 24,
2008
(a)
|
|
$
|
100,000,000
|
|
|
|
4.73
|
%
|
April 1, 2008 to November 3,
2008
|
|
$
|
45,000,000
|
|
|
|
5.73
|
%
|
|
|
|
|
|
|
|
|
|
(a)
In
April 2008, the Company terminated this $100 million interest rate swap
for a cash payment of $899,000.
|
|
The interest rate swaps in the preceding table expose us to market risks for
decreases in interest rates during the periods shown.
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 March 31, 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 6
-
Ex
hibit
s
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††
|
|
|
*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
|
††
|
Filed
under our Commission File
No. 001-10924
|
CLAYTON
WILLIAMS ENERGY, INC.
SIGNATURES
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:
|
May
9, 2008
|
By:
|
/s/
L. Paul Latham
|
|
|
|
L.
Paul Latham
|
|
|
|
Executive
Vice President and Chief
|
|
|
|
Operating
Officer
|
Date:
|
May
9, 2008
|
By:
|
/s/
Mel G. Riggs
|
|
|
|
Mel
G. Riggs
|
|
|
|
Senior
Vice President and Chief Financial
|
|
|
|
Officer
|
37
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