Form 10-Q 6/30/2006
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
[X]
|
Quarterly
Report Pursuant To Section 13 or 15(d) of The Securities Exchange
Act of
1934
|
For
The Quarterly Period Ended June 30, 2006
[
] Transition
Report Pursuant To Section 15(d) of The Securities Exchange Act of
1934
Commission
File Number: 000-51801
ROSETTA
RESOURCES INC.
(Exact
name of registrant as specified in its charter)
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Delaware
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43-2083519
|
(State
or other jurisdiction of incorporation or
organization)
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(I.R.S.
Employer Identification No.)
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717
Texas, Suite 2800, Houston, TX
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77002
|
(Address
of principal executive offices)
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(Zip
Code)
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|
Registrant's
telephone number, including area code: (713)
335-4000
|
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. Yes [X] No [ ]
Indicate
by check mark whether the Registrant is a large accelerated filer, an
accelerated filer or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Securities Exchange Act
of 1934. Large accelerated filer [ ] Accelerated filer [ ] Non-Accelerated
filer
[X]
Indicate
by check mark whether the registrant is a shell company (as defined by Rule
12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]
The
number of shares of the registrant's Common Stock, $.001 par value per share,
outstanding as of August 3, 2006 was 50,696,200.
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3
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20
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28
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28
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31
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32
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35
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35
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35
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35
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35
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36
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37
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Part
I.
Financial Information
Rosetta
Resources Inc.
Consolidated
Balance Sheet
(In
thousands, except per share amounts)
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|
June
30,
2006
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|
December
31,
2005
|
|
Assets
|
|
(Unaudited)
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|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
93,206
|
|
$
|
99,724
|
|
Accounts
receivable
|
|
|
24,930
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|
|
40,051
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|
Derivative
instruments
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|
|
9,792
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|
1,110
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Deferred
income taxes
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|
|
-
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|
|
10,962
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|
Income
tax receivable
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|
|
-
|
|
|
6,000
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|
Other
current assets
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|
12,232
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|
9,411
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Total
current assets
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|
140,160
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|
167,258
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|
Oil
and natural gas properties, full cost method, of which $43.6 million
at
June 30,
2006
and $30.6 million at December 31, 2005 were excluded from amortization
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1,074,642
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973,185
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Other
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3,393
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|
|
2,912
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|
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|
1,078,035
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|
976,097
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|
Accumulated
depreciation, depletion, and amortization
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|
|
(89,480
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)
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|
(40,161
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)
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Total
property and equipment, net
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|
988,555
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|
935,936
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|
Long-term
accounts receivable
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|
792
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|
1,726
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Deferred
loan fees
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|
3,965
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|
4,555
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Deferred
income taxes
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-
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8,594
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Other
assets
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|
1,090
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1,200
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|
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5,847
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|
16,075
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|
Total
assets
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|
$
|
1,134,562
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|
$
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1,119,269
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Liabilities
and Stockholders' Equity
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Current
liabilities:
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Accounts
payable
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$
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17,513
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$
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13,442
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Royalties
payable
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11,444
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15,511
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Derivative
instruments
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-
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29,957
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Interest
payable
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-
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133
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Prepayment
on gas sales
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9,888
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14,528
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Deferred
income taxes
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3,721
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-
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Other
current liabilities
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24,633
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28,264
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Total
current liabilities
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67,199
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101,835
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Long-term
liabilities:
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Derivative
instruments
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28,907
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52,977
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Long-term
debt
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240,000
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240,000
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Asset
retirement obligation
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9,499
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9,034
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Deferred
income taxes
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12,276
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-
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Total
liabilities
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357,881
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403,846
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Commitments
and contingencies (Note 9)
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Stockholders'
Equity:
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Common
stock, $0.001 par value, 150,000,000 shares authorized, 50,302,000
issued
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50
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50
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Additional
paid-in capital
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752,704
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748,569
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Treasury
stock, at cost; 66,831 and no shares at June 30, 2006 and December
31,
2005, respectively.
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(1,246
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)
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-
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Accumulated
other comprehensive loss
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(11,852
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)
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(50,731
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)
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Retained
Earnings
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37,025
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17,535
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Total
stockholders' equity
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776,681
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715,423
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Total
liabilities and stockholders' equity
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$
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1,134,562
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$
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1,119,269
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The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated/Combined
Statements of Operations
(In
thousands, except per share amounts)
(Unaudited)
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Successor-Consolidated
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Predecessor-Combined
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Successor-Consolidated
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Predecessor-Combined
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Three
Months Ended
June
30,
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Six
Months Ended
June
30,
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2006
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2005
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2006
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2005
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Revenues:
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Natural
gas sales
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$
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53,677
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$
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6,895
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$
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110,407
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$
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13,637
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Oil
sales
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9,699
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4,168
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17,508
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8,166
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Oil
and natural gas sales to affiliates
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-
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42,176
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-
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81,952
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Other
revenue
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5
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|
37
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|
10
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|
76
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Total
revenues
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63,381
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53,276
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127,925
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103,831
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Operating
Costs and Expenses:
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Lease
operating expense
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8,323
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9,092
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17,881
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16,629
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Depreciation,
depletion, and amortization
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25,601
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15,555
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49,668
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30,679
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Exploration
expense
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-
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926
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-
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2,355
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Dry
hole costs
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-
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1,886
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-
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1,962
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Treating
and transportation
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|
831
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|
1,030
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|
1,726
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|
1,998
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Affiliated
marketing fees
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|
-
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|
474
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-
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|
913
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Marketing
fees
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|
484
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|
-
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1,108
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-
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Production
taxes
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|
1,626
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|
|
1,567
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|
3,323
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|
|
2,755
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|
General
and administrative costs
|
|
|
7,078
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|
|
6,332
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|
|
16,329
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|
|
9,677
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|
Total
operating costs and expenses
|
|
|
43,943
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|
|
36,862
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|
90,035
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|
|
66,968
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|
Operating
income
|
|
|
19,438
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|
|
16,414
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|
37,890
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|
|
36,863
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|
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Other
(income) expense
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|
|
|
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|
|
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Interest
expense with affiliates, net of interest capitalized
|
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|
-
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|
|
3,378
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|
-
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|
|
6,995
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|
Interest
expense, net of interest capitalized
|
|
|
4,371
|
|
|
-
|
|
|
8,503
|
|
|
-
|
|
Interest
income
|
|
|
(1,115
|
)
|
|
(263
|
)
|
|
(2,252
|
)
|
|
(516
|
)
|
Other
expense, net
|
|
|
152
|
|
|
303
|
|
|
177
|
|
|
207
|
|
Total
other expense
|
|
|
3,408
|
|
|
3,418
|
|
|
6,428
|
|
|
6,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before provision for income taxes
|
|
|
16,030
|
|
|
12,996
|
|
|
31,462
|
|
|
30,177
|
|
Provision
for income taxes
|
|
|
6,066
|
|
|
4,977
|
|
|
11,972
|
|
|
11,496
|
|
Net
income
|
|
$
|
9,964
|
|
$
|
8,019
|
|
$
|
19,490
|
|
$
|
18,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.20
|
|
$
|
0.16
|
|
$
|
0.39
|
|
$
|
0.37
|
|
Diluted
|
|
$
|
0.20
|
|
$
|
0.16
|
|
$
|
0.39
|
|
$
|
0.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
50,229
|
|
|
50,000
|
|
|
50,175
|
|
|
50,000
|
|
Diluted
|
|
|
50,370
|
|
|
50,160
|
|
|
50,361
|
|
|
50,160
|
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated/Combined
Statements of Cash Flows
(In
thousands)
(Unaudited)
|
|
Successor-Consolidated
|
|
Predecessor-Combined
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
2006
|
|
2005
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
19,490
|
|
$
|
18,681
|
|
Adjustments
to reconcile net income to net cash from operating
activities
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
49,668
|
|
|
30,679
|
|
Affiliate
interest expense
|
|
|
-
|
|
|
(6,995
|
)
|
Deferred
income taxes
|
|
|
11,723
|
|
|
2,874
|
|
Amortization
of deferred loan fees recorded as interest expense
|
|
|
590
|
|
|
-
|
|
Income
from unconsolidated investments
|
|
|
(112
|
)
|
|
(161
|
)
|
Stock
compensation expense
|
|
|
3,322
|
|
|
-
|
|
Other
non-cash charges
|
|
|
-
|
|
|
99
|
|
Change
in operating assets and liabilities:
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
15,121
|
|
|
2,378
|
|
Accounts
receivable from affiliates
|
|
|
-
|
|
|
6,298
|
|
Income
taxes receivable
|
|
|
6,000
|
|
|
-
|
|
Other
Assets
|
|
|
(2,624
|
)
|
|
2,563
|
|
Long-term
accounts receivable
|
|
|
934
|
|
|
-
|
|
Royalties
payable
|
|
|
(8,707
|
)
|
|
(1,406
|
)
|
Accounts
payable
|
|
|
3,411
|
|
|
(4,494
|
)
|
Interest
payable
|
|
|
(133
|
)
|
|
-
|
|
Income
taxes payable
|
|
|
-
|
|
|
8,622
|
|
Other
current liabilities
|
|
|
(5,252
|
)
|
|
241
|
|
Net
cash provided by operating activities
|
|
|
93,431
|
|
|
59,379
|
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
Purchases
of property and equipment
|
|
|
(99,563
|
)
|
|
(32,202
|
)
|
Disposals
of property and equipment
|
|
|
36
|
|
|
1,447
|
|
Deposits
|
|
|
25
|
|
|
-
|
|
Other
|
|
|
(14
|
)
|
|
110
|
|
Net
cash used in investing activities
|
|
|
(99,516
|
)
|
|
(30,645
|
)
|
Cash
flows from financing activities
|
|
|
|
|
|
|
|
Equity
offering transaction fees
|
|
|
268
|
|
|
-
|
|
Notes
payable to affiliates
|
|
|
-
|
|
|
(27,239
|
)
|
Proceeds
from issuances of common stock
|
|
|
296
|
|
|
-
|
|
Stock-based
compensation excess tax benefit
|
|
|
249
|
|
|
-
|
|
Purchases
of treasury stock
|
|
|
(1,246
|
)
|
|
-
|
|
Net
cash used in financing activities
|
|
|
(433
|
)
|
|
(27,239
|
)
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash
|
|
|
(6,518
|
)
|
|
1,495
|
|
Cash
and cash equivalents, beginning of period
|
|
|
99,724
|
|
|
-
|
|
Cash
and cash equivalents, end of period
|
|
$
|
93,206
|
|
$
|
1,495
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash disclosures:
|
|
|
|
|
|
|
|
Capital
expenditures included in accrued liabilities
|
|
$
|
2,281
|
|
|
-
|
|
The
accompanying notes to the financial statements are an integral part
hereof
.
Rosetta
Resources Inc.
Notes
to Consolidated/Combined Financial Statements (unaudited)
(1)
|
Organization
and Operations of the
Company
|
Nature
of Operations. Rosetta
Resources Inc. (together with its consolidated subsidiaries, “the Company”) was
formed in June 2005. The Company (“Successor”) is engaged in oil and natural gas
exploration, development, production, and acquisition activities in the United
States. The Company’s main operations are concentrated in the Sacramento Basin
of California, Lobo and Perdido Trends in South Texas, the Gulf of Mexico and
the Rocky Mountains.
These
interim financial statements have not been audited. However, in the opinion
of
management, all adjustments, consisting of only normal recurring adjustments,
necessary for a fair presentation of the financial statements have been
included. Results of operations for interim periods are not necessarily
indicative of the results of operations that may be expected for the entire
year. In addition, these financial statements have been prepared in accordance
with the instructions to Form 10-Q and, therefore, do not include all
disclosures required for financial statements prepared in conformity with
accounting principles generally accepted in the United States of America.
These
financial statements and notes should be read in conjunction with the
Company's audited consolidated/combined financial statements and the notes
thereto included in our Annual Report on Form 10-K for the year ended December
31, 2005.
Certain
reclassifications of prior year balances have been made to conform such amounts
to corresponding 2006 classifications. These reclassifications have no impact
on
net income.
(2)
|
Acquisition
of Calpine Oil and Natural Gas
Business
|
On
July
7, 2005, the Company acquired substantially all of the oil and natural gas
business of Calpine Corporation and certain of its subsidiaries (collectively,
“Calpine” or “Predecessor”), excluding certain non-consent properties described
below, for approximately $910 million. This acquisition (the “Acquisition”) was
funded with the issuance of common stock totaling $725 million and $325 million
of debt from our credit facilities. The transaction was accounted for under
the
purchase method in accordance with SFAS 141. The results of operations were
included in the Company’s financial statements effective July 1, 2005 as the
operating results in the intervening period were not significant. The purchase
price in the Acquisition was calculated as follows:
Cash
from equity offering
|
|
$
|
725,000
|
|
Proceeds
from revolver
|
|
|
225,000
|
|
Proceeds
from term loan
|
|
|
100,000
|
|
Other
purchase price costs
|
|
|
(53,389
|
)
|
Transaction
adjustments (purchase price adjustments)
|
|
|
(11,556
|
)
|
Transaction
adjustments (non-consent properties)
|
|
|
(74,991
|
)
|
Initial
purchase price
|
|
$
|
910,064
|
|
|
|
|
|
|
Other
purchase price costs relate primarily to professional fees of $3.9 million
and
other direct transaction costs of $49.5 million.
The
transaction adjustments (purchase price adjustments) referred to above are
an
amount agreed upon by Calpine and the Company to cover potential costs and/or
revenues that will be adjusted to actual upon the determination of the final
settlement amount for the transaction.
Transaction
adjustments (non-consent properties) referred to above relate to properties
which Calpine determined required third party consents or waivers of
preferential purchase rights in order to effect the transfer of title from
Calpine to the Company or to Calpine entities acquired by the Company in the
Acquisition (collectively, “Non-Consent Properties”). At July 7, 2005, the
Company withheld approximately $75 million of the purchase price with
respect to the Non-Consent Properties. A third party exercised a preferential
right to purchase certain Non-Consent Properties. Such properties will not
be
conveyed to the Company, and the purchase price will be reduced by approximately
$7.4 million. Despite Calpine’s bankruptcy filing, management believes that it
remains likely that conveyance to the Company of substantially all of the
remaining Non-Consent Properties will occur. Upon conveyance of the remaining
Non-Consent Properties, approximately $68 million, being the balance of the
additional purchase price, will be paid to Calpine and will be incremental
to
the purchase price of $910 million. The Company has excluded the
effects of the operating results for the Non-Consent Properties from the
Company's actual results for the six months ended June 30, 2006. If the
assignment of the remaining Non-Consent Properties does not occur, the portion
of the purchase price the Company withheld pending obtaining consent
or waivers for these properties will be available to the Company for
general corporate purposes or to acquire other properties.
The
following is the allocation of the purchase price to specific assets acquired
and liabilities assumed based on estimates of the fair values and costs (In
thousands). There was no goodwill associated with the transaction.
Current
assets
|
|
$
|
1,794
|
|
Non-current
assets
|
|
|
5,087
|
|
Properties,
plant and equipment
|
|
|
925,141
|
|
Current
liabilities
|
|
|
(14,390
|
)
|
Long-term
liabilities
|
|
|
(7,568
|
)
|
|
|
$
|
910,064
|
|
|
|
|
|
|
The
purchase price allocation is preliminary in nature and is subject to change
based upon the manner in which the parties resolve the negotiation associated
with the Company’s revised Final Settlement Statement pertaining to the
Acquisition that was delivered to Calpine on May 12, 2006. In addition to the
$68 million payable to Calpine if and when title is obtained by the Company
for
the remaining Non-Consent Properties, the Company’s revised Final Settlement
Statement includes the proposed payment to Calpine of approximately $12 million
as a true-up of purchase price adjustments arising from net revenues that were
estimated and withheld at the closing of the Acquisition.
The
unaudited pro forma information for the three and six months ended June 30,
2005
assumes the acquisition of Calpine’s domestic oil and natural gas business and
the related financings occurred on January 1, 2004. We believe the
assumptions used provide a reasonable basis for presenting the significant
effects directly attributable to such transactions. The unaudited pro forma
financial statements do not purport to represent what the
Company's results of operations would have been if such transactions had
occurred on such date.
|
|
Three
Months Ended
June
30, 2005
|
|
Six
Months Ended
June
30, 2005
|
|
|
|
(In
thousands, except per share amounts)
|
|
|
|
(Unaudited)
|
|
Revenues
|
|
$
|
53,276
|
|
$
|
103,831
|
|
Net
income
|
|
|
4,157
|
|
|
12,115
|
|
Basic
earnings per common share
|
|
|
0.08
|
|
|
0.24
|
|
Diluted
earnings per common share
|
|
$
|
0.08
|
|
$
|
0.24
|
|
(3)
|
Summary
of Significant Accounting
Policies
|
The
Company has provided discussion of significant accounting policies, estimates
and judgments in the Company's Annual Report on Form 10-K for the year
ended December 31, 2005.
Principles
of Consolidation/Combination and Basis of Presentation. The
Predecessor combined financial statements for the three and six months ended
June 30, 2005 have been prepared from the historical accounting records of
the
domestic oil and natural gas business of Calpine and are presented on a
carve-out basis to include the historical operations of the domestic oil and
natural gas business. The domestic oil and natural gas business of Calpine
was
separately accounted for and managed through direct and indirect subsidiaries
of
Calpine. The combined financial information included herein includes certain
allocations based on the historical activity levels to reflect the combined
financial statements in accordance with accounting principles generally accepted
in the United States of America and may not necessarily reflect the financial
position, results of operations and cash flows of the Company in the future
or
as if the Company had existed as a separate, stand-alone business during the
period presented. The allocations consist of general and administrative expenses
such as employee payroll and related benefit costs and building lease expense,
which were incurred on behalf of Calpine. The allocations have been made on
a
reasonable basis and have been consistently applied for the periods presented.
The
accompanying consolidated financial statements as of June 30, 2006 and December
31, 2005 and for the three and six months ended June 30, 2006 contain the
accounts of Rosetta Resources Inc. and its majority owned subsidiaries after
eliminating all significant intercompany balances and transactions.
Property,
Plant, and Equipment, Net.
In
connection with the Company’s separation from Calpine, the Company adopted the
full cost method of accounting for oil and natural gas properties beginning
July 1, 2005. Under the full cost method, all costs incurred in acquiring,
exploring and developing properties within a relatively large geopolitical
cost
center are capitalized when incurred and are amortized as mineral reserves
in
the cost center are produced, subject to a limitation that the capitalized
costs
not exceed the value of those reserves. In some cases, however, certain
significant costs, such as those associated with offshore U.S. operations,
are
deferred separately without amortization until the specific property to which
they relate is found to be either productive or nonproductive, at
which
time those deferred costs and any reserves attributable to the property are
included in the computation of amortization in the cost center. All costs
incurred in oil and natural gas producing activities are regarded as integral
to
the acquisition, discovery and development of whatever reserves ultimately
result from the efforts as a whole, and are thus associated with the Company’s
reserves. The Company capitalizes internal costs directly identified with
acquisition, exploration and development activities. The Company capitalized
$0.9
million
and $1.7 million of internal costs for the three and six months ended June
30,
2006, respectively. Unevaluated costs are excluded from the full cost pool
and
are periodically evaluated for impairment rather than amortized. Upon
evaluation, costs associated with productive properties are transferred to
the
full cost pool and amortized. Gains or losses on the sale of oil and natural
gas
properties are generally included in the full cost pool unless a significant
portion of the pool is sold.
Capitalized
costs and estimated future development costs are amortized on a
unit-of-production method based on proved reserves associated with the
applicable cost center. The Company assesses the impairment for oil and natural
gas properties for the full cost pool quarterly using a ceiling test to
determine if impairment is necessary. Specifically, the net unamortized costs
for each full cost pool less related deferred income taxes should not exceed
the
following: (a) the present value, discounted at 10%, of future net cash
flows from estimated production of proved oil and gas reserves plus (b) all
costs being excluded from the amortization base plus (c) the lower of cost
or estimated fair value of unproved properties included in the amortization
base
less (d) the income tax effects related to differences between the book and
tax basis of the properties involved. The present value of future cash flows
is
based on current prices, with consideration of price changes only to the extent
provided by contractual arrangements, as of the latest balance sheet presented.
The full cost ceiling test takes into account the prices of qualifying cash
flow
hedges in calculating the current price of the quantities of the future
production of oil and gas reserves covered by the hedges as of the balance
sheet
date. In addition, the effects of using cash flow hedges in calculating the
ceiling test for the portion of future oil and gas production being hedged
has
been consistently applied in all reporting periods. Asset cost in excess of
the
present value of reserves are charged to expense during the period that the
excess occurs. Application of the ceiling test is required for quarterly
reporting purposes, and any write-downs are not reinstated even if the cost
ceiling subsequently increases by year-end. No ceiling test write-down was
recorded for the three or six months ended June 30, 2006
(Successor).
Calpine
followed the successful efforts method of accounting for oil and natural gas
activities. Under the successful efforts method, lease acquisition costs and
all
development costs were capitalized. Exploratory drilling costs were capitalized
until the results were determined. If proved reserves were not discovered,
the
exploratory drilling costs were expensed. Other exploratory costs were expensed
as incurred. Interest costs related to financing major oil and natural gas
projects in progress were capitalized until the projects were evaluated or
until
the projects were substantially complete and ready for their intended use if
the
projects were evaluated as successful. Calpine also capitalized internal costs
directly identified with acquisition, exploration and development activities
and
did not include any costs related to production, general corporate overhead
or
similar activities. The provision for depreciation, depletion, and amortization
was based on the capitalized costs as determined above, plus future abandonment
costs net of salvage value, using the unit of production method with lease
acquisition costs amortized over total proved reserves and other costs amortized
over proved developed reserves.
Calpine
assessed the impairment for oil and natural gas properties on a field by field
basis periodically (at least annually) to determine if impairment of such
properties was necessary. Management utilized its year-end reserve report
prepared by the independent petroleum engineering firm, Netherland,
Sewell & Associates, Inc., and related market factors to estimate the
future cash flows for all proved developed (producing and non-producing) and
proved undeveloped reserves. Property impairments occurred if a field discovered
lower than anticipated reserves, reservoirs produced at a rate below original
estimates or if commodity prices fell below a level that significantly affected
anticipated future cash flows on the property. Proved oil and natural gas
property values were reviewed when circumstances suggested the need for such
a
review and, if required, the proved properties were written down to their
estimated fair market value based on proved reserves and other market factors.
Unproved properties were reviewed quarterly to determine if there was impairment
of the carrying value, with any such impairment charged to expense in the
period. No impairment charge was recorded for the three or six months ended
June
30, 2005 (Predecessor).
Stock-Based
Compensation.
On
January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based
Payments” (“SFAS-123R”). This statement applies to all awards granted, modified,
repurchased or cancelled after January 1, 2006 and to the unvested portion
of
all awards granted prior to that date. The Company adopted this statement using
the modified version of the prospective application (modified prospective
application). Under the modified prospective application, compensation cost
for
the portion of awards for which the employee’s requisite service has not been
rendered that are outstanding as of January 1, 2006 must be recognized as the
requisite service is rendered on or after that date. The compensation cost
for
that portion of awards shall be based on the original fair market value of
those
awards on the date of grant as calculated for recognition under SFAS 123. The
compensation cost for these earlier awards shall be attributed to periods
beginning on or after January 1, 2006 using the attribution method that was
used
under SFAS 123.
The
adoption of the new standard did not have a significant impact on the
Consolidated Balance Sheet with a decrease in retained earnings and an
offsetting increase in additional paid-in capital. On the Consolidated/Combined
Statement of Operations, the adoption of SFAS-123R resulted in decreases in
both
income before income taxes and net income of $1.5 million and $0.9 million,
respectively, for the three months ended June 30, 2006 (Successor) and $3.3
million and $2.0 million, respectively, for the six months ended June 30, 2006
(Successor). The effect on net income per share for basic and diluted was a
reduction $0.02 and $0.04 for the three and six months ended June 30, 2006
(Successor), respectively. See Note 10 of the notes to the Consolidated/Combined
Financial Statements for additional disclosure.
Prior
to
the adoption of SFAS-123R, the Company presented all tax benefit deductions
resulting from the exercise of stock options as operating cash flows in the
accompanying Consolidated/Combined Statement of Cash Flows. SFAS-123R requires
the cash flows that result from tax deductions in excess of the compensation
expense recognized as an operating expense in 2006 and reported in pro forma
disclosures prior to 2006 for those stock options (excess tax benefits) be
classified as financing cash flows. The excess tax benefit for the three and
six
months ended June 30, 2006 (Successor) in the amount of $0.2 million that is
now
classified as financing cash flows would have been classified as an operating
cash flows prior to the adoption of SFAS-123R.
Recent
Accounting Developments
Accounting
Changes and Error Corrections.
In May
2005 the FASB issued SFAS No. 154, Accounting
Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB
Statement No. 3
(“SFAS
154”), which changes the requirements for the accounting for and the reporting
of a change in accounting principle. This Statement applies to all voluntary
changes in accounting principles. It also applies to changes required by an
accounting pronouncement in the unusual instance that the pronouncement does
not
include specific transition provisions. When a pronouncement includes specific
transition provisions, those provisions should be followed. SFAS 154 is
effective for accounting changes and corrections of errors made in fiscal years
beginning after December 15, 2005. The adoption of this Statement did not
impact the Company’s consolidated financial position, results of operations or
cash flows.
Accounting
for Certain Hybrid Financial Instruments.
In
February 2006 , the FASB issued SFAS No. 155, Accounting
for Certain Hybrid Instruments-an amendment of FASB Statements 133 and 140,
which
is
effective for all financial instruments acquired or issued after the beginning
of an entity’s first fiscal year that begins after September 15,
2006.
The
statement improves financial reporting by eliminating the exemption from
applying SFAS No. 133 to interests in securitized financial assets so that
similar instruments are accounted for similarly regardless of the form of the
instruments. The Statement also improves financial reporting by allowing a
preparer to elect fair value measurement at acquisition, at issuance, or when
a
previously recognized financial instrument is subject to a re-measurement event,
on an instrument-by-instrument basis, in cases in which a derivative would
otherwise have to be bifurcated, if the holder elects to account for the whole
instrument on a fair value basis. The adoption of this Statement is not expected
to have a material impact on the Company’s consolidated financial position,
results of operations, or cash flows.
Accounting
for Uncertainty in Income Taxes. In
June
2006, the FASB issued FASB Interpretation No. 48, Accounting
for Uncertainty in Income Taxes -
an
interpretation of FASB Statement No. 109 (“FIN
48”). This interpretation provides guidance for recognizing and measuring
uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income
Taxes.” FIN 48 prescribes a threshold condition that a tax position must meet
for any of the benefit of the uncertain tax position to be recognized in the
financial statements. Guidance is also provided regarding derecognition,
classification and disclosure of these uncertain tax positions. FIN 48 is
effective for fiscal years beginning after December 15, 2006. The adoption
of this Interpretation is not expected to have a material impact on the
Company’s consolidated financial position, results of operations, or cash
flows.
(4)
|
Property,
Plant and Equipment
|
The
Company’s total property and equipment consists of the following:
|
|
June
30,
2006
|
|
December
31,
2005
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$
|
1,045,263
|
|
$
|
951,968
|
|
Unproved
properties
|
|
|
29,379
|
|
|
21,217
|
|
Other
|
|
|
3,393
|
|
|
2,912
|
|
Total
|
|
|
1,078,035
|
|
|
976,097
|
|
Less:
accumulated depreciation, depletion, and amortization
|
|
|
(89,480
|
)
|
|
(40,161
|
)
|
|
|
$
|
988,555
|
|
$
|
935,936
|
|
|
|
|
|
|
|
|
|
Included
in the Company’s oil and gas properties are asset retirement obligations of $9.2
million and $9.1 million as of June 30, 2006 and December 31, 2005,
respectively.
At
June
30, 2006 and December 31, 2005, the Company excluded the following capitalized
costs from depletion, depreciation and amortization:
|
|
June
30,
2006
|
|
December
31,
2005
|
|
Onshore:
|
|
(In
thousands)
|
|
Development
cost
|
|
$
|
1,475
|
|
$
|
1,716
|
|
Exploration
cost
|
|
|
5,651
|
|
|
5,212
|
|
Acquisition
cost of undeveloped acreage
|
|
|
24,777
|
|
|
19,684
|
|
Capitalized
interest
|
|
|
1,219
|
|
|
555
|
|
Total
|
|
|
33,122
|
|
|
27,167
|
|
|
|
|
|
|
|
|
|
Offshore:
|
|
|
|
|
|
|
|
Exploration
cost
|
|
|
7,077
|
|
|
2,407
|
|
Acquisition
cost of undeveloped acreage
|
|
|
3,344
|
|
|
950
|
|
Capitalized
interest
|
|
|
39
|
|
|
28
|
|
Total
|
|
|
10,460
|
|
|
3,385
|
|
|
|
|
|
|
|
|
|
Total
costs excluded from depreciation, depletion, and
amortization
|
|
$
|
43,582
|
|
$
|
30,552
|
|
|
|
|
|
|
|
|
|
In
April
2006, the Company acquired certain oil and gas producing non-operated properties
located in Duval, Zapata, and Jim Hogg Counties, Texas and Escambia County
in
Alabama from Contango Oil and Gas for $11.6 million in cash.
(5)
|
Commodity
Hedging Contracts and Other Derivatives
|
As
of
June 30, 2006, the Company had the following financial fixed price swaps
outstanding with average underlying prices that represent hedged prices of
commodities at various market locations:
Settlement
Period
|
|
Derivative
Instrument
|
|
Hedge
Strategy
|
|
Notional
Daily Volume
MMBtu
|
|
Total
of Notional Volume
MMBtu
|
|
Average
Underlying Prices
MMBtu
|
|
Total
of Proved Natural Gas Production Hedged (1)
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
Swap
|
|
|
Cash
flow
|
|
|
45,000
|
|
|
8,280,000
|
|
$
|
7.92
|
|
|
46
|
%
|
$
|
11,870
|
|
2007
|
|
|
Swap
|
|
|
Cash
flow
|
|
|
36,300
|
|
|
13,249,500
|
|
|
7.62
|
|
|
33
|
%
|
|
(12,927
|
)
|
2008
|
|
|
Swap
|
|
|
Cash
flow
|
|
|
30,876
|
|
|
11,300,616
|
|
|
7.30
|
|
|
27
|
%
|
|
(12,851
|
)
|
2009
|
|
|
Swap
|
|
|
Cash
flow
|
|
|
26,141
|
|
|
9,541,465
|
|
|
6.99
|
|
|
26
|
%
|
|
(9,941
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
42,371,581
|
|
|
|
|
|
|
|
$
|
(23,849
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Estimated based on net gas reserves presented in the December 31, 2005
Netherland, Sewall, & Associates, Inc. reserve report.
As
of
June 30, 2006, the Company had the following costless collar transactions
outstanding with associated notional volumes and contracted ceiling and floor
prices that represent hedge prices at various market locations:
Settlement
Period
|
|
Derivative
Instrument
|
|
Hedge
Strategy
|
|
Notional
Daily Volume
MMBtu
|
|
Total
of Notional Volume
MMBtu
|
|
Average
Floor Price
MMBtu
|
|
Average
Ceiling Price
MMBtu
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
Costless
Collar
|
|
|
Cash
flow
|
|
|
10,000
|
|
|
1,840,000
|
|
$
|
8.825
|
|
$
|
14.000
|
|
$
|
4,733
|
|
The
total
of proved natural gas production hedged in 2006 for the costless collars is
approximately 10% based on the December 31, 2005 reserve report prepared by
Netherland, Sewall, & Associates, Inc.
The
Company’s current cash flow hedge positions are with counterparties who are
lenders in the Company's credit facilities. This allows the Company to
securitize any margin obligation resulting from a negative change in fair market
value of the derivative contracts in connection with the
Company's credit obligations and eliminate the need for independent
collateral postings. As of June 30, 2006, the Company had no deposits
for collateral.
The
following table sets forth the results of third party hedge transactions for
the
respective period for the Consolidated Statement of Operations:
|
|
Three
Months Ended June 30, 2006
|
|
Six
Months Ended June 30, 2006
|
|
Natural
Gas
|
|
|
|
|
|
Quantity
settled (MMBtu)
|
|
|
5,005,000
|
|
|
9,955,000
|
|
Increase
in natural gas sales revenue (In thousands)
|
|
$
|
9,127
|
|
$
|
10,690
|
|
The
Company expects to reclassify gains of $6.1 million to earnings from the balance
in Accumulated Other Comprehensive Loss during the next twelve
months.
At
June
30, 2006, the Company had a derivative instrument current asset of $9.8 million
and no derivative instruments under current liabilities on the Consolidated
Balance Sheet. The derivative instrument assets related to commodities represent
the difference between hedged prices and market prices on hedged volumes of
the
commodities as of June 30, 2006. Hedging activities related to cash settlements
on commodities increased revenues by $9.1 million and $10.7 million for the
three and six months ended June 30, 2006 (Successor).
Gains
and
losses related to ineffectiveness and derivative instruments not designated
as
hedging instruments are included in other income (expense). There was no
ineffectiveness related to cash-flow hedges recorded for the three and six
months ended June 30, 2006 (Successor). There were no gains related to
derivative instruments not designated as hedged instruments for the three and
six months ended June 30, 2005 (Predecessor) as no derivative instruments
existed.
The
Company did not enter into any new derivative instruments during the first
or
second quarters of 2006.
The
Company’s total comprehensive income (loss) is shown below. For 2005, the
Predecessor did not have transactions affecting comprehensive income.
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30, 2006
|
|
June
30, 2006
|
|
|
|
(In
thousands)
|
|
Net
income
|
|
$
|
9,964
|
|
$
|
19,490
|
|
Change
in fair value of derivative hedging instruments
|
|
|
21,648
|
|
|
73,398
|
|
Hedge
settlements reclassified to income
|
|
|
(9,127
|
)
|
|
(10,690
|
)
|
Tax
provision related to hedges
|
|
|
(4,758
|
)
|
|
(23,829
|
)
|
Comprehensive
Income
|
|
$
|
17,727
|
|
$
|
58,369
|
|
The
Company's credit facilities consist of a four-year senior secured revolving
line of credit of up to $400.0 million with a borrowing base of $325.0 million
and a five-year $75.0 million senior second lien term loan. All
amounts drawn under the revolver are due and payable on July 7, 2009. The
principal balance associated with the senior secured lien term loan is due
and
payable on July 7, 2010.
On
June
30, 2006, the Company had outstanding borrowings and letters of credit
of $240.0 million and $1.0 million, respectively. Net borrowing availability
was
$159.0 million at June 30, 2006. The
Company was
in compliance with all covenants at June 30, 2006.
(8)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (ARO) is as
follows:
|
|
Six
Months Ended June 30, 2006
|
|
|
|
(In
thousands)
|
|
ARO
as of January 1, 2006
|
|
$
|
9,467
|
|
Liabilities
incurred during period
|
|
|
98
|
|
Liabilities
settled during period
|
|
|
(14
|
)
|
Accretion
expense
|
|
|
385
|
|
Other
Adjustments
|
|
|
(4
|
)
|
ARO
as of June 30, 2006
|
|
$
|
9,932
|
|
Of
the
total ARO, approximately $0.4 million is classified as a current liability
at
June 30, 2006.
(9)
|
Commitment
and Contingencies
|
The
Company is party to various oil and natural gas litigation matters arising
out
of the normal course of business. Although the ultimate outcome of each of
these
matters cannot be absolutely determined, and the liability the Company may
ultimately incur with respect to any one of these matters in the event of a
negative outcome may be in excess of amounts currently accrued with respect
to
such matters. Management does not believe any such matters will have a
material adverse effect on the Company’s consolidated financial position,
results of operations or cash flows.
Calpine
Bankruptcy
Calpine
Corporation and certain of its subsidiaries filed for protection under the
federal bankruptcy laws in the United States Bankruptcy Court of the Southern
District of New York (the “Court) on December 20, 2005. Calpine Energy Services,
L.P., which filed for bankruptcy, has continued to make the required deposits
into the Company’s margin account and to timely pay for natural gas production
it purchases from the Company’s subsidiaries under various natural gas supply
agreements. As part of the Acquisition, Calpine and the Company entered into
a
Transition Services Agreement, pursuant to which services were to be provided
to
the Company through July 6, 2006. Calpine and certain of its subsidiaries have
generally continued to provide the services requested by
the
Company under the Transition Services Agreement. Additionally, Calpine Producer
Services, L.P., which filed for bankruptcy, generally is performing its
obligations under the Marketing and Services Agreement with the
Company.
There
remains the possibility, however, that there will be issues between the Company
and Calpine that could amount to material contingencies in relation to the
Purchase and Sale Agreement and interrelated agreements concurrently executed
therewith, dated July 7, 2005, by and among Calpine, the Company, and various
other signatories thereto (collectively, the “Purchase Agreement”), including
unasserted claims and assessments with respect to (i) the still pending Purchase
Agreement and the amounts that will be payable in connection therewith, (ii)
whether or not Calpine and its affiliated debtors will, in fact, perform their
remaining obligations in connection with the Purchase Agreement; and (iii)
the
ultimate disposition of the remaining Non-Consent Properties (and related
royalty revenues). Calpine has specific obligations to the Company under the
Purchase Agreement relating to these matters, and also has “further assurances”
duties to the Company under the Purchase Agreement.
In
addition, as to certain of the other oil and natural gas properties the
Company purchased from Calpine in the Acquisition and for which payment was
made on July 7, 2005, the Company will seek additional documentation from
Calpine to eliminate any open issues in the Company's title or
resolve any issues as to the clarity of the Company's ownership. Requests
for additional documentation are customary in connection with transactions
similar to the Acquisition. In the Acquisition, certain of these
properties require ministerial governmental action approving the Company as
qualified assignee and operator, which is typically required even though in
most
cases Calpine has already conveyed the properties to the Company free
and clear of mortgages and liens in favor of Calpine’s creditors. As to certain
other properties, the documentation delivered by Calpine at closing under the
Purchase Agreement was incomplete. The Company remains hopeful that the Company
will continue to work cooperatively with Calpine to secure these ministerial
governmental approvals and to accomplish the curative corrections for all of
these properties. In addition, as to all properties acquired by the Company
in
the Acquisition, Calpine contractually agreed to provide the Company with such
further assurances as the Company may reasonably request. Nevertheless, as
a
result of Calpine’s bankruptcy filing, it remains uncertain as to whether
Calpine will respond cooperatively. If Calpine does not fulfill its contractual
obligations and does not complete the documentation necessary to resolve these
issues, the Company will pursue all available remedies, including but
not limited to a declaratory judgment to enforce the Company's rights
and actions to quiet title. After pursuing these matters, if the Company
experiences a loss of ownership with respect to these properties without
receiving adequate consideration for any resulting loss to the Company, an
outcome the Company's management considers to be remote, then the Company could
experience losses which could have a material adverse effect on the
Company's consolidated financial condition, statement of operations and
cash flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Court seeking the entry of an order authorizing Calpine to
assume certain oil and gas leases Calpine has previously sold or agreed to
sell
to the Company in the Acquisition, to the extent those leases constitute
“unexpired leases of non-residential real property” and were not fully
transferred to the Company at the time of Calpine’s filing for bankruptcy.
According to this motion, Calpine filed the motion in order to avoid the
automatic forfeiture of any interest it may have in these leases by operation
of
a statutory deadline. Calpine’s motion did not request that the Court
determine whether these properties belong to the Company or Calpine, but the
Company understands it was meant to allow Calpine to preserve and avoid
forfeiture under the Bankruptcy Code of whatever interest Calpine may possess,
if any, in these oil and gas leases. The Company disputes Calpine’s contention
that it may have an interest in any significant portion of these oil and gas
leases and intends to take the necessary steps to protect all of the Company’s
rights and interest in and to the leases. On July 7, 2006, the Company filed
an
objection in response to Calpine’s motion, wherein the Company asserted that oil
and gas leases constitute interests in real property that are not subject to
“assumption” under the Bankruptcy Code. In the objection the Company also
requested that (a) the Court eliminate from the order certain Federal offshore
leases from the Calpine motion because these properties were fully conveyed
to
the Company in July 2005, and the Minerals Management Service has subsequently
recognized the Company as owner and operator of these properties, and (b) any
order entered by the Court be without prejudice to, and fully preserve our
rights, claims and legal arguments regarding the characterization and ultimate
disposition of the remaining described oil and natural gas properties. In the
Company’s objection, the Company also urged the Court to require the parties to
promptly address and resolve any remaining issues under the pre-bankruptcy
definitive agreements with Calpine and proposed to the Court that the parties
seek arbitration (or at least mediation) to complete the following:
|
·
|
Calpine’s
conveyance of the Non Consent Properties to the
Company;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which the Company
has
already paid Calpine; and
|
|
·
|
Resolution
of the final amounts the Company is to pay Calpine, which the Company
has
concluded are approximately $80 million, consisting of roughly $68
million
for the Non Consent Properties and approximately $12 million in other
true-up payment obligations.
|
At
a
hearing held on July 12, 2006, the Court in Calpine Corporation’s bankruptcy
took the following steps:
|
·
|
In
response to an objection filed by the Department of Justice and
asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion
those
leases issued by the United States (and managed by the Department
of
Interior) and the State of California (and managed by the California
State
Lands Commission). Calpine and the Department of Justice agreed
to an
extension of the existing deadline to November 15, 2006 to assume
such Oil
and Gas Leases under Section 365 of the Bankruptcy Code, to the
extent the
Oil and Gas Leases are leases subject to Section 365. The effect
of these
actions is to render the objection of the Company inapplicable
at this
time; and
|
|
·
|
The
Court also encouraged Calpine and the Company to arrive at a business
solution to all remaining issues including approximately $68 million
payable to Calpine for conveyance of the Non Consent Properties.
|
On
August
1, 2006, the Company filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts and unliquidated damages in amounts that cannot
presently be determined. The
Company continues to work with Calpine on a cooperative and expedited basis
toward resolution of unresolved conveyance of properties and post-closing
adjustments under the Purchase Agreement.
The
Company continues to believe that it is unlikely that any challenges by the
Calpine debtors or their creditors to the fairness of the Acquisition would
be
successful. However, there can be no assurance that Calpine, its creditors
or
interest holders may not challenge the fairness of some or all of the
Acquisition. For a number of reasons, including the Company's understanding
of
the process that Calpine followed in allowing market forces to set the
purchase price for the Acquisition, the Company believes that it is unlikely
that any challenge to the fairness of the Acquisition would be successful.
Environmental
Environmental
expenditures are expensed or capitalized, as appropriate, depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations, and that do not have future economic benefit, are
expensed. Liabilities related to future costs are recorded on an undiscounted
basis when environmental assessments and/or remediation activities are probable
and the cost can be reasonably estimated. The Company performed an environmental
remediation study for two sites in California and correspondingly, recorded
a
liability, which at June 30, 2006 and December 31, 2005 was $0.1 million
and $0.7 million, respectively. The Company does not expect that the outcome
of
our environmental matters discussed above will have a material adverse effect
on
the Company’s consolidated financial position, results of operations or cash
flows.
Participation
in a Regional Carbon Sequestration Partnership
The
Company has made preliminary preparations in connection with the
Company participating in the United States Department of Energy’s (“DOE”)
Regional Carbon Sequestration Partnership program (“WESTCARB”) with the
California Energy Commission and the University of California, Lawrence Berkeley
Laboratory. The Company has been selected by the DOE for this project. Under
WESTCARB, the Company would be required to drill a carbon injection well,
recondition an idle well for use as an observation well and provide WESTCARB
with certain proprietary well data and technical assistance related to the
evaluation and injection of carbon dioxide into a suitable natural gas reservoir
in the Sacramento Basin. The Company’s maximum contribution to WESTCARB is $1.0
million and will be limited to 20% of the total contributions to the project.
The Company will not have any obligation under the WESTCARB project until it
has
entered into an acceptable contract and the project has obtained proper and
necessary local, state and federal regulatory approvals, land use authorizations
and third party property rights. No accrual was recorded at June 30, 2006 as
the
study is still in the preliminary stage.
(10)
|
Stock-Based
Compensation
|
Adoption
of SFAS-123R
On
January 1, 2003, Calpine prospectively adopted the fair market value method
of accounting for stock-based employee compensation pursuant to SFAS
No. 123, “Accounting for Stock-Based Compensation”, as amended by SFAS
No. 148, “Accounting for Stock-Based Compensation-Transition and
Disclosure” (“SFAS No. 123”). Expense amounts included in the combined
historical financial statements for the three and six months ended June 30,
2005
are based on stock based compensation granted to employees by Calpine. Stock
options were granted at an option price equal to the quoted market price at
the
date of the grant or award.
In
determining the Company’s accounting policies, the Company chose to apply the
intrinsic value method pursuant to Accounting Standards Board (“APB”)
No. 25, “Stock Issued to Employees” (“APB No. 25”), effective July 1, 2005.
Under APB No. 25, no compensation expense is recognized when the exercise
price for options granted equals the fair value of the Company’s common stock on
the date of the grant. Accordingly, the provisions of SFAS No. 123 permit
the continued use of the method prescribed by APB No. 25 but require
additional disclosures, including pro forma calculations of net income (loss)
per share as if the
fair
value method of accounting prescribed by SFAS No. 123 had been
applied.
Effective
January 1, 2006, the Company began accounting for stock-based compensation
under
SFAS-123R, whereby the Company records stock-based compensation expense based
on
the fair value of awards described below. Stock-based compensation expense
recorded for all share-based payment arrangements for the three and six months
ended June 30, 2006 (Successor) was $1.5 million and $3.3 million, with a tax
benefit of $0.6 million and $1.2 million, respectively. For the three and six
months ended June 30, 2005 (Predecessor), stock-based compensation expense
recorded was $0.1 million and $0.2 million with a tax benefit of $0.01 million
and $0.1 million, respectively. The remaining compensation expense associated
with total unvested awards as of June 30, 2006 was $10.3 million and will be
recognized over a weighted average period of 1.29 years.
Successor
2005
Long-Term Incentive Plan
In
July
2005, the Board of Directors adopted the Rosetta 2005 Long-Term Incentive Plan
(the "Plan") whereby stock is granted to employees, officers and directors
of
the Company. The Plan allows for the grant of stock options, stock awards,
restricted stock, restricted stock units, stock appreciation rights, performance
awards and other incentive awards. The Plan provides for administration by
the
Compensation Committee or another committee of our Board of Directors (the
“Committee”), which determines the type and size of award and sets the terms,
conditions, restrictions and limitations applicable to the award within the
confines of the Plan’s terms. Employees, non-employee directors and other
service providers of Rosetta and the Company’s affiliates who, in the opinion of
the Committee, are in a position to make a significant contribution to the
success of Rosetta and the Company’s affiliates are eligible to participate in
the Plan. The maximum number of shares available for grant under the plan is
3,000,000 shares of common stock plus any shares of common stock that become
available under the Plan for any reason other than exercise, such as shares
traded for the related tax liabilities of employees. The maximum number of
shares of common stock available for grant of awards under the Plan to any
one
participant is (i) 300,000 shares during any fiscal year in which the
participant begins work for Rosetta and (ii) 200,000 shares during each
fiscal year thereafter.
Stock
Options
The
Company has granted stock options under its 2005 Long-Term Incentive Plan.
Options generally expire ten years from the date of grant. The exercise price
of
the options can not be less than the fair market value per share of the
Company’s common stock on the grant date.
The
weighted average fair value at date of grant for options granted during the
six
months ended June 30, 2006 (Successor) and 2005 (Predecessor) was $10.74 and
$1.27 per share, respectively. The fair value of options granted is estimated
on
the date of grant using the Black-Scholes option-pricing model with the
following assumptions:
|
|
Successor
|
|
Predecessor
|
|
|
|
Six
Months Ended
June
30, 2006
|
|
Six
Months Ended
June
30, 2005
|
|
Expected
option term (years)
|
|
|
6.5
|
|
|
2.5
|
|
Expected
volatility
|
|
|
56.65
|
%
|
|
58.00
|
%
|
Expected
dividend rate
|
|
|
0.00
|
%
|
|
0.00
|
%
|
Risk
free interest rate
|
|
|
4.33%
- 5.15
|
%
|
|
3.62
|
%
|
The
Company has assumed an annual forfeiture rate of 5 % for the awards granted
in
2006 based on the Company’s history for this type of award to various employee
groups. Compensation expense is recognized ratably over the requisite service
period and immediately for retirement-eligible employees.
The
following table summarizes information related to outstanding and exercisable
options held by the Company’s employees at June 30, 2006:
|
|
Shares
|
|
Weighted
Average Exercise Price
Share
|
|
Weighted
Average Remaining Contractual Term
(In
years)
|
|
Aggregate
Intrinsic Value
(In
thousands)
|
|
Outstanding
at the December 31, 2005
|
|
|
706,550
|
|
$
|
16.28
|
|
|
|
|
|
|
|
Granted
|
|
|
213,950
|
|
|
17.94
|
|
|
|
|
|
|
|
Exercised
|
|
|
(18,500
|
)
|
|
16.02
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(33,625
|
)
|
|
16.28
|
|
|
|
|
|
|
|
Outstanding
at June 30, 2006
|
|
|
868,375
|
|
$
|
16.70
|
|
|
9.21
|
|
$
|
201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
Exercisable at June 30, 2006
|
|
|
210,512
|
|
$
|
16.34
|
|
|
9.17
|
|
$
|
56
|
|
Stock-based
compensation expense recorded for stock option awards for the three and six
months ended June 30, 2006 (Successor) is $1.0 million and $1.5 million,
respectively. Stock-based compensation expense recorded for stock option awards
for the three and six months ended June 30, 2005 (Predecessor) is $0.1 million
and $0.2 million, respectively. Unrecognized expense as of June 30, 2006 for
all
outstanding stock options is $5.7 million.
The
total
intrinsic value of options exercised during the six months ended June 30, 2006
was $0.1 million. For the three and six months ended June 30, 2005, the
Predecessor did not have any options exercised. The fair value of awards vested
for the six months ended June 30, 2006 was $5.2 million.
Restricted
Stock
The
Company has granted stock under its 2005 Long-Term incentive Plan with a maximum
contractual life of three years. The fair value of restricted stock grants
is
based on the value of the Company’s common stock on the date of grant.
Compensation expense is recognized ratably over the requisite service period.
The Company also assumes an annual forfeiture rate of 5 % for these awards
based
on the Company’s history for this type of award to various employee
groups.
The
following table summarizes information concerning restricted stock held by
the
Company’s employees at June 30, 2006:
|
|
Shares
|
|
Weighted
Average Grant Date Fair Value
|
|
Non-vested
shares outstanding at December 31, 2005
|
|
|
581,900
|
|
$
|
16.27
|
|
Granted
|
|
|
107,800
|
|
|
17.79
|
|
Vested
|
|
|
(280,000
|
)
|
|
16.07
|
|
Forfeited
|
|
|
(23,500
|
)
|
|
16.28
|
|
Non-vested
shares outstanding at June 30, 2006
|
|
|
386,200
|
|
$
|
16.83
|
|
|
|
|
|
|
|
|
|
The
non-vested restricted stock outstanding at June 30, 2006 vests at a rate of
25%
on the first anniversary of the date of grant, 25% on the second anniversary
and
50% on the third anniversary. The restrictions on 270,000 shares lapsed on
the
day after the Company’s effective date of its recently completed initial public
offering in February 2006 and therefore vested in the first quarter of 2006.
Stock-based
compensation expense recorded for restricted stock awards for the three and
six
months ended June 30, 2006 was $0.5 million and $1.8 million, respectively.
Unrecognized expense as of June 30, 2006 for all outstanding restricted stock
awards is $4.6 million.
Predecessor
Retirement
Savings Plan
The
Predecessor had a defined contribution savings plan, under Section 401(a)
and 501(a) of the Internal Revenue Code, in which the Predecessor’s employees
were eligible to participate. The defined contribution savings plan provided
for
tax deferred salary deductions and after-tax employee contributions. Employees
were immediately eligible upon hire. Contributions included employee salary
deferral contributions and employer profit-sharing contributions made entirely
in cash of 4% of employees’ salaries, with employer contributions capped at
$8,400 per year for 2005. There were no employer profit-sharing contributions
for the three and six months ended June 30, 2005.
2000
Employee Stock Purchase Plan
The
Predecessor adopted the 2000 Employee Stock Purchase Plan (“ESPP”) in May 2000.
The Predecessor’s eligible employees could, in the aggregate, purchase up to
28,000,000 shares of common stock at semi-annual intervals through periodic
payroll deductions. Purchases were limited to either a maximum value of $25,000
per calendar year based on the IRS Code Section 423 limitation or limited
to 2,400 shares per purchase interval. Shares were purchased on May 31 and
November 30 of each year until termination of the plan on May 31,
2010. Under the ESPP, 36,817 shares were issued to Calpine’s employees at a
weighted average fair market value of $2.53 per share, for the six months ended
June 30, 2005. The purchase price was 85% of the lower of (i) the fair
market value of the common stock on the participant’s entry date into the
offering period, or (ii) the fair market value on the semi-annual purchase
date. The purchase price discount was significant enough to cause the ESPP
to be
considered compensatory under SFAS No. 123. As a result, the ESPP was
accounted for as stock-based compensation in accordance with SFAS No. 123
for the six months ended June 30, 2005. For the six months ended June 30, 2005,
compensation expense of $0.2 million was recorded under the ESPP.
1996
Stock Incentive Plan
The
Predecessor adopted the 1996 Stock Incentive Plan (“SIP”) in September 1996 in
which certain of the Company’s employees were eligible to participate. The SIP
succeeded the Predecessor’s previously adopted stock option program. Under the
SIP, the option exercise price generally equaled the stock’s fair market value
on date of grant. The SIP options generally vested ratably over four years
and
expired after 10 years. As of June 30, 2005, the amount of shares outstanding
under the 1996 incentive plan were 754,284.
Basic
earnings per share is computed by dividing income available to common
stockholders by the weighted average number of shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if
contracts to issue common stock and related stock options were exercised at
the
end of the period.
The
following is a calculation of basic and diluted weighted average shares
outstanding:
|
|
Successor
|
|
Predecessor
|
|
Successor
|
|
Predecessor
|
|
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Basic
weighted average number of shares outstanding
|
|
|
50,229
|
|
|
50,000
|
|
|
50,175
|
|
|
50,000
|
|
Dilution
effect of stock option and awards at the end of
the
period
|
|
|
141
|
|
|
160
|
|
|
186
|
|
|
160
|
|
Diluted
weighted average number of shares outstanding
|
|
|
50,370
|
|
|
50,160
|
|
|
50,361
|
|
|
50,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
awards and shares excluded from diluted earnings
per
share due to anti-dilutive effect
|
|
|
206
|
|
|
-
|
|
|
154
|
|
|
-
|
|
The
Company has one reportable segment, oil and natural gas exploration and
production, as determined in accordance with SFAS No. 131, “Disclosure
About Segments of an Enterprise and Related Information.” See below for
information by geographic location.
Geographic
Area Information
The
Company owns oil and natural gas interests in eight main geographic areas all
within in the United States. Geographic revenue and property, plant and
equipment information below for the three and six months ended June 30, 2006
and
2005 are based on physical location of the assets at the end of each period.
|
|
Successor
|
|
Predecessor
|
|
Successor
|
|
Predecessor
|
|
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2006
(1)
|
|
2005
|
|
2006
(1)
|
|
2005
|
|
Oil
and Natural Gas Revenue
|
|
(In
thousands)
|
|
California
|
|
$
|
15,710
|
|
$
|
21,203
|
|
$
|
36,100
|
|
$
|
43,385
|
|
Lobo
|
|
|
13,673
|
|
|
13,877
|
|
|
29,082
|
|
|
26,474
|
|
Perdido
|
|
|
6,962
|
|
|
6,508
|
|
|
16,784
|
|
|
12,380
|
|
State
Waters
|
|
|
2,142
|
|
|
2,331
|
|
|
5,289
|
|
|
2,345
|
|
Other
Onshore
|
|
|
8,315
|
|
|
4,245
|
|
|
12,175
|
|
|
7,662
|
|
Gulf
of Mexico
|
|
|
6,394
|
|
|
4,553
|
|
|
15,921
|
|
|
10,542
|
|
Rockies
|
|
|
622
|
|
|
86
|
|
|
964
|
|
|
161
|
|
Mid-Continent
|
|
|
431
|
|
|
472
|
|
|
910
|
|
|
842
|
|
Other
|
|
|
5
|
|
|
1
|
|
|
10
|
|
|
40
|
|
|
|
$
|
54,254
|
|
$
|
53,276
|
|
$
|
117,235
|
|
$
|
103,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Excludes
the effects of hedging.
|
|
|
Successor
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
2006
(2)
|
|
2005
(2)
|
|
|
|
(In
thousands)
|
|
Oil
and Natural Gas Properties
|
|
|
|
|
|
California
|
|
$
|
408,493
|
|
$
|
386,513
|
|
Lobo
|
|
|
378,302
|
|
|
368,276
|
|
Perdido
|
|
|
38,345
|
|
|
25,983
|
|
State
Waters
|
|
|
18,622
|
|
|
12,067
|
|
Other
Onshore
|
|
|
98,675
|
|
|
75,737
|
|
Gulf
of Mexico
|
|
|
92,763
|
|
|
77,416
|
|
Rockies
|
|
|
31,494
|
|
|
21,224
|
|
Mid-Continent
|
|
|
7,948
|
|
|
5,969
|
|
Other
|
|
|
3,393
|
|
|
2,912
|
|
|
|
$
|
1,078,035
|
|
$
|
976,097
|
|
|
|
|
|
|
|
|
|
|
(2)
|
Oil
and natural gas properties at June 30, 2006 and December 31, 2005
are
reported gross. Under the full cost method of accounting for oil
and gas
properties, depreciation, depletion and amortization is not allocated
to
properties.
|
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
Various
statements, other than statements of historical fact, included in this report,
are forward-looking statements. In some cases, you can identify a
forward-looking statement by terminology such as “may”, “could”, “should”,
“expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”,
“predict”, “potential”, “pursue”, “target” or “continue”, the negative of such
terms or other comparable terminology.
The
forward-looking statements contained in this report are largely based on our
expectations, which reflect estimates and assumptions made by our management.
These estimates and assumptions reflect our best judgment based on currently
known market conditions and other factors. Although we believe such estimates
and assumptions to be reasonable, they are inherently uncertain and involve
a
number of risks and uncertainties that are beyond our control. Management’s
assumptions about future events may prove to be inaccurate. For a more detailed
description of the risks and uncertainties, see Item 1A. Risk Factors in our
annual report on Form 10-K for the year ended December 31, 2005. We do not
intend to publicly update or revise any forward-looking statements as a result
of new information, future events or otherwise. These cautionary statements
qualify all forward-looking statements attributable to us, or persons acting
on
our behalf. Management cautions all readers that the forward-looking statements
contained in this report are not guarantees of future performance, and we cannot
assure any reader that such statements will be realized or the forward-looking
events and circumstances will occur. Actual results may differ materially from
those anticipated or implied in the forward-looking statements due to various
factors, including:
·
|
The
timing and extent of changes in commodity prices, particularly natural
gas;
|
·
|
Various
drilling and exploration risks that may delay or prevent commercial
operation of new wells;
|
·
|
Economic
slowdowns that can adversely affect consumption of oil and natural
gas by
businesses and consumers;
|
·
|
Resources
expended in connection with Calpine’s bankruptcy including our increased
costs for lawyers, consultant experts and related expenses, as well
as the
lost opportunity costs associated with its internal resources dedicated
to
these matters;
|
·
|
Uncertainties
that actual costs may be higher than estimated;
|
·
|
Factors
that impact the exploration of oil or natural gas resources, such
as the
geology of a resource, the total amount and costs to develop recoverable
reserves, and legal title, regulatory, natural gas administration,
marketing and operational factors relating to the extraction of oil
and
natural gas;
|
·
|
Uncertainties
associated with estimates of oil and natural gas reserves;
|
·
|
Our
ability to access the capital markets on attractive terms or at
all;
|
·
|
Refusal
by or inability of our current or potential counterparties or vendors
to
enter into transactions with us or fulfill their obligations to us;
|
·
|
Our
inability to obtain credit or capital in desired amounts or on favorable
terms;
|
·
|
Present
and possible future claims, litigation and enforcement actions;
|
·
|
Effects
of the application of regulations, including changes in regulations
or the
interpretation thereof;
|
·
|
Availability
of processing and transportation;
|
·
|
Potential
for disputes with mineral lease and royalty owners regarding calculation
and payment of royalties, including basis of pricing, adjustment
for
quality, measurement and allowable costs and expenses;
|
·
|
Developments
in oil-producing and natural gas-producing countries;
|
·
|
Competition
in the oil and natural gas industry; and
|
·
|
Adverse
weather conditions, hurricanes, tropical storms, earthquakes, mud
slides,
flooding and other natural disasters which may occur in areas of
the
United States in which we have operations, including the Federal
waters of
the Gulf of Mexico, as well as new energy package insurance coverage
limitations related to any single named windstorm; and uncertainty
with
respect to potential environmental, health and safety
liabilities.
|
ITEM
2. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
Overview
Rosetta
Resources Inc. is an independent oil and natural gas company engaged in the
acquisition, exploration, development and production of natural gas and oil
properties in the United States. We were formed as a Delaware corporation in
June 2005. In July 2005, we acquired the domestic oil and natural gas business
of Calpine Corporation and its affiliates. Our main operations are concentrated
in the Sacramento Basin of California, Lobo and Perdido Trends in South Texas,
the Gulf of Mexico and the Rocky Mountains.
In
this
section, we sometimes refer to Rosetta as “Successor”, and we sometimes refer to
Calpine Corporation and its affiliates, from whom we acquired our initial
domestic oil and natural gas business and associated oil and gas properties
as
“Predecessor”. Additionally, we sometimes refer to our acquisition of Calpine’s
domestic oil and natural gas business as the “Acquisition”.
Higher
oil and natural gas prices have led to higher demand for drilling rigs,
operating personnel and field supplies and services, and have caused increases
in the costs of those goods and services. Given the inherent volatility of
oil
and natural gas prices that are influenced by many factors beyond our control,
we plan our activities and budget based on conservative sales price assumptions.
We focus our efforts on increasing natural gas reserves and production while
controlling costs at a level that is appropriate for long-term operations.
Our
future earnings and cash flows are dependent on our ability to manage our
overall cost structure to a level that allows for profitable production. Our
future earnings will also be impacted by the changes in fair market value of
hedges we executed to mitigate the volatility in the changes of oil and natural
gas prices in future periods when such positions are settled as these
instruments meet the criteria to be accounted for as cash flow hedges. Until
settlement, the changes in fair market value of our hedges will be included
as a
component of stockholder’s equity to the extent effective. In periods of rising
prices, these transactions will mitigate future earnings and in periods of
declining prices will increase future earnings in the respective period the
positions are settled.
Like
all
oil and natural gas exploration and production companies, we face the challenge
of natural production declines. As initial reservoir pressures are depleted,
oil
and natural gas production from a given well naturally decreases. Thus, an
oil
and natural gas exploration and production company depletes part of its asset
base with each unit of oil or natural gas it produces. We attempt to overcome
this natural decline by drilling and acquiring more reserves than we produce.
Our future growth will depend on our ability to continue to add reserves in
excess of production. We will maintain our focus on costs to add reserves
through drilling and acquisitions as well as the costs necessary to produce
our
reserves. Our ability to add reserves through drilling is dependent on our
capital resources and can be limited by many factors, including our ability
to
timely obtain drilling permits and regulatory approvals. The permitting and
approval process has been more difficult in recent years than in the past due
to
increased activism from environmental and other groups and has extended the
time
it takes us to receive permits. We can be disproportionately disadvantaged
by
delays in obtaining or failing to obtain drilling approvals compared to
companies with larger or more dispersed property bases. As a result, we are
less
able to shift drilling activities to areas where permitting may be easier and
we
have fewer properties over which to spread the costs related to complying with
these regulations and the costs of foregone opportunities resulting from
delays.
Financial
Highlights
In
the
first six months of 2006, we produced 15.7 Bcfe with average revenue of $8.15
per Mcfe. Our natural gas production for the six months ended June 30, 2006
was
14.0 Bcf and our oil production for the same period was 270.8 MBbls.
Our average natural gas prices were $7.89 per Mcf and average oil prices for
the
same period were $64.65 per Bbl. For the six months ended June 30, 2006, we
had
revenues of $127.9 million including the effects of hedging with net income
of
$19.5 million and earnings per share of $0.39.
Calpine
Bankruptcy
On
December 20, 2005, Calpine and certain of its subsidiaries, including Calpine
Fuels, filed for protection under federal bankruptcy laws in the United States
Bankruptcy Court of the Southern District of New York (“the Court”). The filing
raises certain concerns regarding aspects of our relationship with Calpine
which
we will closely monitor as the Calpine bankruptcy proceeds. The following are
our principal areas of concern:
|
·
|
Calpine,
its creditors or interest holders may challenge the fairness of some
or
all of the Acquisition. For a number of reasons, including our
understanding of the process which Calpine followed in allowing market
forces to set the purchase price for the Acquisition, we believe
that it
is unlikely that any challenge to the fairness of the Acquisition
would be
successful.
|
|
·
|
The
bankruptcy proceeding may prevent, frustrate or delay our ability
to
receive record legal title to certain properties originally listed
as
determined to be Non-Consent Properties which we are entitled to
obtain
under the Purchase Agreement.
|
|
·
|
Additionally,
the bankruptcy proceeding may prevent, frustrate or delay our ability
to
receive corrective documentation from Calpine for certain properties
that
we bought from Calpine and paid for, in cases where Calpine delivered
incomplete documentation, including documentation related to certain
ministerial governmental approvals.
|
|
·
|
Calpine
may stop purchasing gas from us under our gas purchase contracts
with
Calpine. Since the date of the bankruptcy filing, Calpine has continued
buying natural gas from us and making timely payments. Calpine has
sought
and obtained bankruptcy court approval to continue payments to us
for our
delivery of natural gas under our gas purchase and sale contracts
with
Calpine. Under the terms of these contracts, in the event of Calpine’s
default in making timely payments, we are entitled to suspend deliveries
to Calpine and instead sell this gas to third parties at comparable
prices
and terms until Calpine cures any such default (Calpine having 60
days
after notice to do so). In terms of the likely impact of Calpine’s default
under these contracts, should this ever occur, we expect to be able
to
minimize our exposure for Calpine’s non-payment to four days of sales
under these contracts, or approximately $1.4 million in lost sales
at
production rates and prices as of June 30, 2006.
|
|
·
|
Calpine
may stop providing us certain services, including natural gas marketing
services and pipeline services, which Calpine, through separate
subsidiaries that are also debtors in the Calpine bankruptcy, currently
provides to us. Management does not believe that cessation of these
services would have a material impact on our
operations.
|
Transfers
Pending at Calpine’s Bankruptcy
At
the
closing of the Acquisition on July 7, 2005, we retained approximately $75
million of the purchase price in respect to Non-Consent Properties identified
by
Calpine as requiring third party consents or waivers of preferential rights
to
purchase that were not received before closing. Those Non-Consent Properties
were not included in conveyances delivered at the closing. Subsequent analysis
determined that a portion of the Non-Consent Properties, with an approximate
allocation value of $29 million under the Purchase Agreement did not require
consents or waivers. For that portion of the Non-Consent Properties for which
third party consents were in fact required (having an approximate value of
$39
million under the Purchase Agreement) and those Non-Consent Properties that
did
not require consents or waivers, we believe that Calpine was and is obligated
to
have transferred to us the record title, free of any mortgages and other liens,
in each case where we obtained the required consents or waivers.
The
approximate allocated value under the Purchase Agreement for the portion of
the
Non-Consent Properties subject to a preferential right to purchase is $7.1
million. We have retained $7.4 million of the purchase price under the Purchase
Agreement for the Non-Consent Properties subject to preferential rights to
purchase, which total amount includes approximately $0.3 million for a property
which was transferred to us but will be transferred to the appropriate third
party under an exercised preferential purchase right. These properties will
not
be conveyed to us and we have retained the $7.4 million previously withheld
pending receipt of waivers of the preferential rights to purchase.
We
believe all conditions precedent for our receipt of record title, free of any
mortgages or other liens, for substantially all of the Non-Consent Properties
(excluding that portion of these properties subject to preferential rights
to
purchase) were satisfied earlier, and certainly no later than December 15,
2005,
when we tendered once again the amounts necessary to conclude the settlement
of
the Non-Consent Properties.
We
believe we are the equitable owner of each of these remaining Non-Consent
Properties and that such properties are not part of Calpine’s bankruptcy estate.
Upon our receipt from Calpine of record title, free of any mortgages or other
liens, to these remaining Non-Consent Properties, we are prepared to pay Calpine
approximately $68 million, subject to appropriate adjustment for the associated
net revenues and expenses through December 15, 2005. Our statement of operations
for the six months ended June 30, 2006 does not include any net revenues or
production from any of the Non-Consent Properties.
If
Calpine does not provide us with record title, free of any mortgages for all
of
these properties and other liens, to any of the Non-Consent Properties
(excluding that portion of these properties subject to preferential rights
to
purchase), we will have a total of approximately $68 million available to us
for
general corporate purposes, including for the purpose of acquiring additional
properties. We also have approximately $7.4 million, previously withheld for
that portion of the Non-Consent Properties subject to preferential rights to
purchase, which will also be available to us for general corporate purposes,
including for the purpose of acquiring additional properties.
In
addition, as to certain of the other oil and natural gas properties we purchased
from Calpine in the Acquisition and for which payment was made on July 7, 2005,
we will seek additional documentation from Calpine to eliminate any open issues
in our title or resolve any issues as to the clarity of our ownership.
Requests for additional documentation are customary in connection with
transactions such as the Acquisition. In the Acquisition, certain of these
properties require ministerial governmental action approving us as qualified
assignee and operator, which is typically required even though in most cases
Calpine has already conveyed the properties to us free and clear of mortgages
and liens in
favor
of
Calpine’s creditors. As to certain other properties, the documentation delivered
by Calpine at closing under the Purchase Agreement was incomplete. We remain
hopeful that we will continue to work cooperatively with Calpine to secure
these
ministerial governmental approvals and to accomplish the curative corrections
for all of these properties. In addition, as to all properties acquired by
us in
the Acquisition, Calpine contractually agreed to provide us with such further
assurances as we may reasonably request. Nevertheless, as a result of Calpine’s
bankruptcy filing, it remains uncertain as to whether Calpine will respond
cooperatively. If Calpine does not fulfill its contractual obligations and
does
not complete the documentation necessary to resolve these issues, we will pursue
all available remedies, including but not limited to a declaratory judgment
to
enforce our rights and actions to quiet title. After pursuing these matters,
if
we experience a loss of ownership with respect to these properties without
receiving adequate consideration for any resulting loss to us, an outcome we
consider to be remote, then we could experience losses which could have a
material adverse effect on our consolidated financial condition, statement
of
operations and cash flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Court seeking the entry of an order authorizing Calpine to
assume certain oil and gas leases Calpine has previously sold or agreed to
sell
to us in the acquisition, to the extent those leases constitute “unexpired
leases of non-residential real property” and were not fully transferred to us at
the time of Calpine’s filing for bankruptcy. According to this motion, Calpine
filed the motion in order to avoid the automatic forfeiture of any interest
it
may have in these leases by operation of a statutory deadline. Calpine’s motion
did not request that the Court determine whether these properties belong to
us
or Calpine, but we understand it was meant to allow Calpine to preserve and
avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may
possess, if any, in these oil and gas leases. We dispute Calpine’s contention
that it may have an interest in any significant portion of these oil and gas
leases and intend to take the necessary steps to protect all of our rights
and
interest in and to the leases. On July 7, 2006, we filed an objection in
response to Calpine’s motion, wherein we asserted that oil and gas leases
constitute interests in real property that are not subject to “assumption” under
the Bankruptcy Code. The objection also requested that (a) the Court eliminate
from the order certain Federal offshore leases from the Calpine motion because
these properties were fully conveyed to us in July 2005, and the Minerals
Management Service has subsequently recognized us as owner and operator of
these
properties and (b) any order entered by the Court be without prejudice to,
and
fully preserve our rights, claims and legal arguments regarding the
characterization and ultimate disposition of the remaining described oil and
gas
properties. In our objection, we also urged the Court to require the parties
to
promptly address and resolve any remaining issues under the pre-bankruptcy
Purchase Agreement with Calpine and proposed to the Court that the parties
seek
arbitration (or at least mediation) to complete the following:
|
·
|
Calpine’s
conveyance of the Non Consent Properties to
us;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and gas properties for which we have already paid
Calpine; and
|
|
·
|
Resolution
of the final amounts we are to pay Calpine, which we have concluded
are
approximately $80 million, consisting of roughly $68 million for
the Non
Consent Properties and approximately $12 million in other true-up
payment
obligations.
|
At
a
hearing held on July 12, 2006, the Court in Calpine Corporation’s bankruptcy
took the following steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Department
of
Interior) and the State of California (and managed by the California
State
Lands Commission). Calpine and the Department of Justice agreed to
an
extension of the existing deadline to November 15, 2006 to assume
such Oil
and Gas Leases under Section 365 of the Bankruptcy Code, to the extent
the
Oil and Gas Leases are leases subject to Section 365. The effect
of these
actions is to render our objection inapplicable at this time;
and
|
|
·
|
The
Court also encouraged Calpine and us to arrive at a business solution
to
all remaining issues including approximately $68 million payable
to
Calpine for conveyance of the Non Consent Properties.
|
On
August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts and unliquidated damages in amounts that can
not
presently be determined. We
continue to work with Calpine on a cooperative and expedited basis toward
resolution of unresolved conveyance of properties and post-closing adjustments
under the Purchase Agreement.
Critical
Accounting Policies and Estimates
In
our
Annual Report on Form 10-K for the year ended December 31, 2005, we identified
our most critical accounting policies
upon
which our financial condition depends as those relating to oil and natural
gas
reserves, full cost method of accounting, derivative transactions and hedging
activities, asset retirement obligations, income taxes and stock-based
compensation.
On
January 1, 2006, we adopted the accounting policies described in SFAS No. 123
(revised 2004) “Share-Based Payments” (“SFAS-123R”). This statement applies to
all awards granted, modified, repurchased or cancelled after January 1, 2006
and
to the unvested portion of all awards granted prior to that date. We adopted
this statement using the modified version of the prospective application
(modified prospective application). Under this method, no prior year amounts
have been restated. Prior to January 1, 2006, we accounted for stock-based
compensation in accordance with the intrinsic value based method prescribed
by
the Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock
Issued to Employees”.
With
the
adoption of SFAS-123R, one of the differences in our method of accounting is
that unvested stock options are now expensed as a component of stock-based
compensation recorded in General and Administrative Costs in the
Consolidated/Combined Statement of Operations. This expense is based on the
fair
value of the award at the original grant date and is recognized over the
remaining vesting period. Prior to the adoption of SFAS-123R, this amount was
included as a pro forma disclosure in the Notes to the Consolidated Financial
Statements. Compensation expense for the three and six months ended June 30,
2006 (Successor) was $1.5 million and $3.3 million, respectively.
In
addition, the application of the forfeiture rate in calculating the fair value
has changed with the adoption of SFAS-123R. We are now required to estimate
forfeitures on all equity-based compensation and adjust period expenses instead
of recording the actual forfeitures as they occur. Furthermore, we are required
to immediately expense certain awards to retirement eligible employees depending
on the structure of each individual plan. The retirement eligibility provision
only applies to new grants that were awarded after January 1, 2006.
Results
of Operations
In
July
2005, we acquired the domestic oil and natural gas business of Calpine
Corporation and affiliates. Due to the Acquisition, the results of operations
for the three and six months ended June 30, 2006 and 2005 are presented as
Successor and Predecessor, Successor comprising the three and six months ended
June 30, 2006 and Predecessor comprising the three and six months ended June
30,
2005. These two periods have not been compared because of differences in
accounting principles, primarily the full cost method of accounting for oil
and
natural gas properties adopted by us and the successful efforts method of
accounting for oil and natural gas properties followed by Calpine. In addition,
Calpine adopted on January 1, 2003, SFAS No. 123, “Accounting for
Stock-Based Compensation” to measure the cost of employee services received in
exchange for an award of equity instruments, whereas we adopted the intrinsic
value method of accounting for stock options and stock awards effective
July 1, 2005, and as required, have adopted the guidance for stock based
compensation under SFAS-123R effective January 1, 2006. We believe
comparative results of operations for the two periods would be misleading and,
therefore, have chosen to present the periods separately.
Successor
Revenues. Our
revenues are derived from the sale of our oil and natural gas production, which
includes the effects of qualifying hedge contracts. Total revenue of $63.4
million for the second quarter consists primarily of natural gas sales
comprising 85% of total revenue on total volumes of 8.0 Bcfe. For the six months
ended June 30, 2006, gas sales comprised 86% of total revenue on total volumes
of 15.7 Bcfe.
|
|
Three
Months Ended
June
30, 2006
|
|
Six
Months Ended
June
30, 2006
|
|
|
|
(In
thousands, expect per unit amounts)
|
|
Total
revenues
|
|
$
|
63,381
|
|
$
|
127,925
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
7.1
|
|
|
14.0
|
|
Oil
(MBbls)
|
|
|
143.6
|
|
|
270.8
|
|
Total
Equivalents (Bcfe)
|
|
|
8.0
|
|
|
15.7
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$
|
7.56
|
|
$
|
7.89
|
|
Avg.
Gas Price per Mcf excluding Hedging
|
|
|
6.28
|
|
|
7.12
|
|
Avg.
Oil Price per Bbl
|
|
|
67.54
|
|
|
64.65
|
|
Avg.
Revenue per Mcfe
|
|
$
|
7.92
|
|
$
|
8.15
|
|
Natural
Gas.
Natural
gas sales revenue was $53.7 million, including the effects of hedging, based
on
total gas production volumes of 7.1 Bcf for the three months ended June 30,
2006. Approximately 80% of the production volumes were from the following three
areas: California, Lobo and Perdido. The average natural gas prices were $7.56
per Mcf for the respective period. The effect of hedging on natural gas sales
revenue was an increase of $9.1 million for an increase in total price from
$6.28 to $7.56 per Mcf.
Natural
gas sales revenue was $110.4 million, including the effects of hedging, based
on
total gas production volumes of 14.0 Bcf for the six months ended June 30,
2006.
Approximately 79% of the production volumes were from California, Lobo and
Perdido. The average natural gas prices were $7.89 per Mcf for respective
period. The effect of hedging on natural gas sales revenue was an increase
of
$10.7 million for an increase in total price from $7.12 to $7.89 per
Mcf.
Crude
Oil.
Oil
revenue was $9.7 million based on production volumes of 143.6 MBbls for the
three months ended June 30, 2006. Production volumes were 63.5 MBbls for Gulf
of
Mexico and 51.6 MBbls for Other Onshore both representing approximately 80%
of the total production. The average oil price was $67.54 per Bbl.
Oil
revenue was $17.5 million based on production volumes of 270.8 MBbls for the
six
months ended June 30, 2006. Production volumes were 139.0 MBbls for Gulf of
Mexico, 72.2 MBbls for Other Onshore and 23.9 MBbls for Lobo resulting in
approximately 87% of the total production. The offshore production volumes
were
higher than expected due to minimal downtime on most of the offshore wells
in
High Island and East Cameron. The average oil price was $64.65 per
Bbl.
Operating
Expenses
The
following table presents information about our operating expenses for the three
and six months ended June 30, 2006.
|
|
Three
Months Ended
June
30, 2006
|
|
Six
Months Ended
June
30, 2006
|
|
|
|
(In
thousands, expect per unit amounts)
|
|
Lease
operating expense
|
|
$
|
8,323
|
|
$
|
17,881
|
|
Depreciation,
depletion and amortization
|
|
|
25,601
|
|
|
49,668
|
|
Treating
and transportation
|
|
|
831
|
|
|
1,726
|
|
Marketing
fees
|
|
|
484
|
|
|
1,108
|
|
Production
taxes
|
|
|
1,626
|
|
|
3,323
|
|
General
and administrative costs
|
|
$
|
7,078
|
|
$
|
16,329
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$
|
1.04
|
|
$
|
1.14
|
|
Avg.
DD&A per Mcfe
|
|
|
3.20
|
|
|
3.16
|
|
Avg.
transportation & marketing per Mcfe
|
|
|
0.16
|
|
|
0.18
|
|
Avg.
production tax expense per Mcfe
|
|
|
0.20
|
|
|
0.21
|
|
Avg.
G&A per Mcfe
|
|
$
|
0.88
|
|
$
|
1.04
|
|
Our
operating expenses for the three and six months ended June 30, 2006 are
primarily related to the following items:
|
·
|
Lease
Operating Expense.
Lease operating expense of $8.3 million related directly to oil and
natural gas volumes which totaled 8.0 Bcfe for the three months ended
June
30, 2006 or costs of $1.04 per Mcfe. The costs included work over
cost, ad
valorem taxes, insurance, well servicing and equipment
rentals.
|
Lease
operating expense of $17.9 million related directly to oil and natural gas
volumes which totaled 15.7 Bcfe for the six months ended June 30, 2006 or costs
of $1.14 per Mcfe. In addition, lease operating costs were affected by the
number of wells that came on-line in South Texas.
|
·
|
Depreciation,
Depletion, and Amortization.
Depreciation, depletion, and amortization expense for the three and
six
month period ended was $25.6 million and $49.7 million, respectively,
under the full cost method of accounting for oil and natural gas
properties. The depletion rate was $3.16 per Mcfe in the second quarter
of
2006.
|
|
·
|
General
and Administrative Costs.
General and administrative costs for the three and six months ended
June
30, 2006 were $7.1 million and $16.3 million net of capitalization
of
general and administrative costs of $0.9 million and $1.7 million,
respectively, as a component of our oil and natural gas properties
under
the full cost method of accounting for oil and natural gas properties.
General and administrative costs include salary and employee benefits
as
well as legal,
|
consulting,
and auditing fees. In addition, stock compensation expense for the three and
six
months ended June 30, 2006 of $1.5 million and $3.3 million is recorded in
general and administrative costs.
Total
Other (income) expense.
Other
(income) expense is composed of interest expense of $4.4 million and $8.5
million for the three and six months ended June 30, 2006, respectively, and
interest income of $1.1 million and $2.3 million for the same periods,
respectively. The interest expense is associated with the note payable and
interest income is related to the interest earned on the overnight investments
of the Company’s cash balances.
Provision
for Income Taxes.
The
effective tax rate for the three and six months ended June 30, 2006 was 37.8%
and 38.1%, respectively. The provision for income taxes differs from the tax
computed at the federal statutory income tax rate primarily due to state taxes,
tax credits and other permanent differences.
Predecessor
Revenues. Total
Revenues of $53.3 million and $103.8 million for the three and six months ended
June 30, 2005, respectively, consists primarily of natural gas sales comprising
92 % of total revenue. Production volumes for the three and six months ended
June 30, 2005 were 7.5 Bcfe and 15.5 Bcfe, respectively. Production volumes
were
lower than expected due to capital expenditure constraints resulting in reduced
drilling activity.
|
|
Three
Months Ended
June
30, 2005
|
|
Six
Months Ended
June
30, 2005
|
|
|
|
(In
thousands, expect per unit amounts)
|
|
Total
revenues
|
|
$
|
53,276
|
|
$
|
103,831
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
7.0
|
|
|
14.5
|
|
Oil
(MBbls)
|
|
|
81.2
|
|
|
163.8
|
|
Total
equivalents per (Bcfe)
|
|
|
7.5
|
|
|
15.5
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$
|
7.02
|
|
$
|
6.59
|
|
Avg.
Oil Price per Bbl
|
|
|
51.33
|
|
|
49.86
|
|
Avg.
Revenue per Mcfe
|
|
$
|
7.10
|
|
$
|
6.70
|
|
Natural
Gas.
Natural
gas sales revenue was $49.1 million based on total gas production volumes of
7.0
Bcf for the three months ended June 30, 2005. There were no effects of hedging
on the revenue or production amounts as no derivative instruments existed during
the three and six months ended June 30, 2005.
Natural
gas sales revenue was $95.6 million with gas production volumes of 14.5 Bcf
for
the six months ended June 30, 2005. The production volumes were primarily from
the Sacramento Basin with 6.5 Bcf or 44.8% and South Texas, Lobo with 3.7 Bcf
and Perdido with 1.8 Bcf, for a combined production of 5.5 Bcf or 37.9%.
Production volumes were lower than expected due to capital expenditure
constraints resulting in reduced drilling activity. The average price for
natural gas was $6.59 per Mcf.
Crude
Oil.
Oil
sales revenue was $4.2 million with oil production of 81.2 MBbls for the three
months ended June 30, 2005. The average oil price was $51.33 per Bbl. For the
six months ended June 30, 2005 oil sales revenue was $8.2 million with
production volumes of 163.8 MBbls with an average price of $49.86 per Bbl.
Production volumes were primarily from the Gulf of Mexico region which produced
72.7 MBbls or 44% of oil production.
Operating
Expenses
The
following table presents information about our operating expenses for the three
and six months ended June 30, 2005.
|
|
Three
Months Ended
June
30, 2005
|
|
Six
Months Ended June 30, 2005
|
|
|
|
(In
thousands, expect per unit amounts)
|
|
Lease
operating expense
|
|
$
|
9,092
|
|
$
|
16,629
|
|
Depreciation,
depletion and amortization
|
|
|
15,555
|
|
|
30,679
|
|
Exploration
expense
|
|
|
926
|
|
|
2,355
|
|
Dry
hole costs
|
|
|
1,886
|
|
|
1,962
|
|
Treating
and transportation
|
|
|
1,030
|
|
|
1,998
|
|
Affiliated
marketing fees
|
|
|
474
|
|
|
913
|
|
Production
taxes
|
|
|
1,567
|
|
|
2,755
|
|
General
and administrative costs
|
|
|
6,332
|
|
|
9,677
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$
|
1.21
|
|
$
|
1.08
|
|
Avg.
DD&A (excluding impairments) per Mcfe
|
|
|
2.07
|
|
|
1.98
|
|
Avg.
transportation & marketing per Mcfe
|
|
|
0.20
|
|
|
0.19
|
|
Avg.
production tax expense per Mcfe
|
|
|
0.21
|
|
|
0.18
|
|
Avg.
G&A per Mcfe
|
|
$
|
0.84
|
|
$
|
0.63
|
|
The
operating expenses for the three and six months ended June 30, 2005 are
primarily related to the following items:
|
·
|
Lease
Operating Expense.
Lease operating expense of $9.1 million related directly to oil and
natural gas volumes which totaled 7.5 Bcfe for the three months ended
June
30, 2005 or costs of $1.21 per Mcfe. The costs included work over
cost, ad valorem taxes, insurance, well servicing and equipment rentals.
For the six months ended June 30, 2005, lease operating expense was
$16.6
million related to total oil and gas volumes of 15.5 Bcfe or $1.08
per
Mcfe. The costs include work over cost of $0.22 per Mcfe, ad valorem
taxes
of $0.22 per Mcfe and insurance of $0.06 per Mcfe.
|
|
·
|
Depreciation,
Depletion, and Amortization.
Depreciation, depletion, and amortization expense was $15.6 million
and
$30.7 million for the three and six months ended June 30, 2005,
respectively. The predecessor used the successful efforts method
of
accounting for oil and natural gas properties during the above periods.
The depletion rate was $1.97 per Mcfe for the six months ended June
30,
2005
|
|
·
|
Exploration
expense.
Exploration expense was $0.9 million and $2.4 million for the three
and
six months ended June 30, 2005, respectively, under the successful
efforts
method of accounting for oil and natural gas properties. The exploration
expense was comprised of geological and geophysical salaries and
expenses.
|
|
·
|
Production
Taxes.
Production taxes are primarily based on wellhead values of production
and
vary across the different regions. Production taxes as a percentage
of
natural gas and oil sales were approximately 2.9% and 2.7% for the
three
and six months ended June 30, 2005, respectively.
|
|
·
|
General
and Administrative Costs.
General and administrative costs for the three and six months ended
June
30, 2005 were $6.3 million and $9.7 million, which are net of capitalized
general and administrative costs of $2.4 million and $3.6 million,
respectively. General and administrative costs are comprised of items
such
as salaries and employee benefits, legal fees, and contract fees.
For the
six months ended June 30, 2005, of the $9.7 million in total general
and
administrative costs, $5.9 million relates to salary and employee
benefits. In addition, $1.3 million are legal costs and $1.7 million
are
merger and acquisition costs, which relate to the sale of the oil
and
natural gas business to the
Company.
|
Other
(income) expense.
Other
(income) expense is comprised of interest expense of $3.4 million and $7.0
million for the three and six months ended June 30, 2005, respectively, and
is
associated with the intercompany debt with Calpine Corporation.
Provision
for Income Taxes.
The
effective tax rate for the three and six months ended June 30, 2005 was 38.3%
and 38.1%, respectively. The provision for income taxes differs from the tax
computed at the federal statutory income tax rate primarily due to state taxes,
tax credits and other permanent differences.
Liquidity
and Capital Resources
Our
cash
flows depend on many factors, including the price of oil and natural gas and
the
success of our development and exploration activities as well as future
acquisitions. We actively manage our exposure to commodity price fluctuations
by
executing
derivative
transactions to hedge the change in prices of our production thereby mitigating
our exposure to price declines, but these transactions will also limit our
earnings potential in periods of rising natural gas prices. This derivative
transaction activity will allow us the flexibility to continue to execute our
capital plan if prices decline during the period our derivative transactions
are
in place. In addition, the majority of our capital expenditures will be
discretionary and could be curtailed if our cash flows declined from expected
levels. In connection with entering into our credit facilities in July 2005,
we
entered into a series of natural gas fixed-price swaps for a significant portion
of our expected production through 2009. Consistent with our hedge policy,
in
December 2005, we entered into two costless collar transactions, which are
intended to establish a floor price and ceiling price for approximately 10,000
MMBtu per day which represents approximately 10% of our 2006 natural gas
production based on a third party reserve report at December 31, 2005. The
effects of these derivative transactions on our financial statements are
discussed above under “Results of Operations - Natural Gas”. Additionally, we
may enter into other agreements including fixed-price, forward price, physical
purchase and sales contracts, futures, financial swaps, option contracts and
put
options.
Senior Secured
Revolving Line of Credit.
BNP
Paribas, in July 2005 provided us with a senior secured revolving line of
credit concurrent with the Acquisition in the amount of up to $400.0 million.
This revolving line of credit was syndicated to a group of lenders on
September 27, 2005. Availability under the revolver is restricted to the
borrowing base, which initially was $275.0 million and was reset to $325.0
million, upon amendment, as a result of the hedges put in place in
July 2005 and the favorable effects of the exercise of the over-allotment
option we granted in our private equity offering in July 2005 through which
we
received $70.0 million of funds (net of transaction fees). In July 2005, we
repaid $60.0 million of the $225.0 million in original borrowings on the
Revolver. The borrowing base is subject to review and adjustment on a
semi-annual basis and other interim adjustments, including adjustments based
on
our hedging arrangements. Amounts outstanding under the revolver bear interest,
as amended, at specified margins over the London Interbank Offered Rate (LIBOR)
of 1.25% to 2.00%. Such margins will fluctuate based on the utilization of
the
facility. Borrowings under the Revolver are collateralized by perfected first
priority liens and security interests on substantially all of our assets,
including a mortgage lien on oil and natural gas properties having at least
80%
of the PV-10 reserve value, a guaranty by all of our domestic subsidiaries,
a
pledge of 100% of the stock of domestic subsidiaries, a lien on cash securing
the Calpine gas purchase and sale contracts and $15 million of cash on-hand.
These collateralized amounts under the mortgages are subject to semi-annual
reviews based on updated reserve information. We are subject to the financial
covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the
end
of each fiscal quarter and a maximum leverage ratio of not greater than 3.5
to
1.0, calculated at the end of each fiscal quarter for the four fiscal quarters
then ended, measured quarterly with the pro forma effect of acquisitions and
divestitures. At June 30, 2006, our current ratio was 4.3 and our leverage
ratio
was 1.4. In addition, we are subject to covenants limiting dividends and other
restricted payments, transactions with affiliates, incurrence of debt, changes
of control, asset sales, and liens on properties. We were in compliance with
all
covenants at June 30, 2006. All amounts drawn under the revolver are due and
payable on July 7, 2009. Availability under the revolving line of credit
was $159.0 million at June 30, 2006.
Second
Lien Term Loan. BNP
Paribas, in July 2005, also provided us with a second lien term loan
concurrent with the Acquisition, in the amount of $100.0 million. On
September 27, 2005, we repaid $25.0 million of borrowings on the Term Loan,
reducing the balance to $75.0 million and syndicated the loan to a group of
lenders including BNP Paribas. Borrowings under the term loan initially bore
interest at LIBOR plus 5.00%. As a result of the hedges put in place in July
2005 and the favorable effects of our private equity placement, as described
above, the interest rate for the second lien term loan has been reduced to
LIBOR
plus 4.00%. The loan is collateralized by second priority liens on substantially
all of our assets. We are subject to the financial covenants of a minimum asset
coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of
not
more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the
four
fiscal quarters then ended, measured quarterly with the pro forma effect of
acquisitions and divestitures. In addition, we are subject to covenants limiting
dividends and other restricted payments, transactions with affiliates,
incurrence of debt, changes of control, asset sales, and liens on properties.
We
were in compliance with all covenants at June 30, 2006. The revised principal
balance is due and payable on July 7, 2010.
Cash
Flows
|
|
Successor
|
|
Predecessor
|
|
|
|
Six
months ended June 30,
|
|
|
|
2006
|
|
2005
|
|
(In
thousands)
|
|
Cash
flows provided by operating activities
|
|
$
|
93,431
|
|
$
|
59,379
|
|
Cash
flows used in investing activities
|
|
|
(99,516
|
)
|
|
(30,645
|
)
|
Cash
flows used in financing activities
|
|
|
(433
|
)
|
|
(27,239
|
)
|
Net
(decrease) increase in cash and cash equivalents
|
|
$
|
(6,518
|
)
|
$
|
1,495
|
|
|
|
|
|
|
|
|
|
Operating
Activities.
Key
drivers of net cash provided by operating activities are commodity prices,
production volumes and costs and expenses, which primarily include operating
costs, taxes other than income taxes, transportation expense and
administrative
expenses.
Net
cash
provided from operating activities for the six months ended June 30, 2006 was
$93.4 million generated from total production of 15.7 Bcfe with revenue of
$127.9 million and net income of $31.5 million before taxes. Natural gas prices
averaged $7.89 per Mcf, including the effects of hedging, and oil averaged
$64.65 per Bbl.
Net
cash
provided from operations for the six months ended June 30, 2005 was $59.4
million generated from total production of 15.5 Bcfe with revenue of $103.8
million and net income of $30.2 million before tax. Natural gas prices averaged
$6.59 per Mcf and oil averaged $49.86 per Bbl during the quarter.
Investing
Activities.
The
primary driver of cash used in investing activities is capital
spending.
Cash
used
in investing activities for the six months ended June 30, 2006 was $99.5 million
primarily relating to the purchases of property and equipment with additional
capital expenditures accrued for at quarter end.
Cash
used
in investing activities for the six months ended June 30, 2005 was $30.6 million
related to drilling and completion work and lease acquisitions less sale of
assets.
Financing
Activities.
The
primary driver of cash used in financing activities is equity transactions,
the
acquisition of new debt facilities or increases in intercompany notes payable
and corresponding repayments of debt.
Net
cash
used in financing activities for the six months ended June 30, 2006 was $0.4
million primarily related to the purchases of treasury stock of $1.2 million
offset by the equity offering transaction fees, proceeds from issuances of
common stock and stock-compensation excess tax benefit.
Net
cash
used in financing activities for the six months ended June 30, 2005 was
comprised of repayments of notes to affiliates totaling $27.2
million.
Capital
Expenditures
Our
capital expenditures for the six months ended June 30, 2006 were $101.8 million.
These capital expenditures were primarily associated with increased drilling
activity in California and the Texas State Waters. We believe we have adequate
expected cash flows from operations and available borrowings under our revolving
credit facility to cover our budgeted capital expenditures.
Item
3. Quantitative and Qualitative Disclosures About Market
Risk
We
are
currently exposed to market risk primarily related to adverse changes in oil
and
natural gas prices and interest rates. We use derivative instruments to manage
our commodity price risk caused by fluctuating prices. We do not enter into
derivative instruments for trading purposes. For information regarding our
exposure to certain market risks, see Item 7A. “Quantitative and Qualitative
Disclosure About Market Risks” in our annual report filed on Form 10-K for the
year ended December 31, 2005. There have been no significant changes in our
market risk from what was disclosed in the Form 10-K for the year ended December
31, 2005.
Under
the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of
the
effectiveness of the design and operation of our disclosure controls and
procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934, as amended (“Exchange Act”), as of June 30, 2006.
Disclosure controls and procedures are those controls and procedures designed
to
provide reasonable assurance that the information required to be disclosed
in
our Exchange Act filings is (1) recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission’s rules
and forms, and (2) accumulated and communicated to management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.
Based
on
that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that, as of June 30, 2006, our disclosure controls and procedures
were
not effective, at the reasonable assurance level, due to the identification
of
the material weaknesses in internal control over financial reporting described
below. Notwithstanding the material weaknesses described below, we believe
our
unaudited consolidated financial statements included in this quarterly filing
on
Form 10-Q fairly present in all material respects our financial position,
results of operations and cash flows for the periods presented in accordance
with generally accepted accounting principles as applicable to interim
reporting.
In
preparing our Exchange Act filings, including this quarterly filing on Form
10-Q, we implemented processes and procedures to
provide
reasonable assurance that the identified material weaknesses in our internal
control over financial reporting were mitigated with respect to the information
that we are required to disclose. As a result, we believe, and our Chief
Executive Officer and Chief Financial Officer have certified to their knowledge,
that this quarterly filing on Form 10-Q does not contain any untrue statements
of material fact or omit to state any material fact necessary to make the
statements made, in light of the circumstances under which such statements
were
made, not misleading with respect to the period covered in this
report.
Material
Weaknesses in Internal Control Over Financial Reporting
A
material weakness is a control deficiency, or combination of control
deficiencies, that results in more than a remote likelihood that a material
misstatement of the annual or interim financial statements will not be prevented
or detected. We have identified various deficiencies in internal control over
financial reporting. We believe that many of these are attributable to our
transition from a subsidiary of a much larger company to a stand alone entity.
In connection with the preparation of our unaudited consolidated financial
statements and our assessment of the effectiveness of our disclosure controls
and procedures as of June 30, 2006 to be included in this Quarterly Report
on
Form 10-Q to be filed under the Exchange Act, we determined the following
specific control deficiencies, which represent material weaknesses in our
internal control over financial reporting as of June 30, 2006:
|
a)
|
We
did not have a sufficient compliment of permanent personnel to have
an
appropriate accounting and financial reporting organizational structure
to
support the activities of the Company. Specifically, we did not have
permanent personnel with an appropriate level of accounting knowledge,
experience and training in the selection, application and implementation
of generally accepted accounting principles and financial reporting
commensurate with our financial reporting
requirements.
|
|
b)
|
We
did not have effective controls as it relates to the identification
and
documentation of accounting policies, including selection and application
of generally accepted accounting principles used for accounting for
select
transactions and other activities. This deficiency resulted in a
reduced
ability to ensure the timely and accurate recording of certain
transactions and activities primarily relating to accounting for
derivatives and debt modifications. As a result, we did not have
sufficient procedures to ensure significant underlying select transactions
were appropriately and timely accounted for in the general
ledger.
|
In
addition, these material weaknesses could result in a misstatement of
substantially all accounts and disclosures which would result in a material
misstatement of annual or interim financial statements that would not be
prevented or detected. Accordingly, management has concluded that these control
deficiencies constitute material weaknesses. These material weaknesses also
existed at December 31, 2005 and March 31, 2006.
Remediation
Activities
As
discussed above, management has identified certain material weaknesses that
exist in our internal control over financial reporting and management is taking
steps to strengthen our internal control over financial reporting. During 2006,
we employed additional accounting personnel and began improving our
documentation of our accounting policies and procedures. Specifically, we have
taken the following remedial actions:
|
1.
|
We
employed a certified public accountant with specific expertise in
accounting software systems to evaluate and implement further enhancements
to our software and related procedures to improve our accounting
control;
|
|
2.
|
We
have replaced our manager of fixed assets and accounts payable with
a more
highly credentialed person having a masters degree in business
administration who is also a certified public accountant and have
authorized the hiring of a senior fixed asset
accountant;
|
|
3.
|
We
employed a person to fill the position of manager of internal audit
to
review and audit our internal control environment and make recommendations
for improvement;
|
|
4.
|
We
employed a certified public accountant from one of the top tier Accounting
Firms to be the manager of financial
reporting;
|
|
5.
|
We
employed two supervisory level accountants who have extensive industry
experience; and
|
|
6.
|
We
have made substantial progress on the establishment and documentation
of
our accounting policies and
procedures.
|
While
we
have taken certain actions to address the material weaknesses identified,
additional measures may be necessary. These measures will be taken to address
the material weaknesses identified to provide reasonable assurance that our
internal control over financial reporting is effective.
Beginning
with the year ending December 31, 2007, pursuant to Section 404 of the
Sarbanes-Oxley Act, we will be required to deliver a report that assesses the
effectiveness of our internal control over financial reporting, and our auditors
will be required to audit and report on our assessment of and the effectiveness
of our internal control over financial reporting. We are in the process of
completing the documentation and testing of our internal control over financial
reporting and remediating any additional material weaknesses identified during
that activity. Accordingly, we may not be able to complete the required
management assessment by our reporting deadline. An inability to complete this
assessment would result in receiving something other than an unqualified report
from our auditors with respect to our assessment of our internal control over
financial reporting. In addition, if material weaknesses are not remediated,
we
would not be able to conclude that our internal control over financial reporting
was effective, which would result in the inability of our external auditors
to
deliver an unqualified report on the effectiveness of our internal control
over
financial reporting.
We
and
our subsidiaries are party to various oil and natural gas litigation matters
arising from time to time in the ordinary course of business. While the outcome
of these proceedings cannot be predicted with certainty, we do not expect these
matters to have a material adverse effect on the financial
statements.
We
carry
insurance with coverage and coverage limits consistent with our assessment
of
risks in our business and of an acceptable level of financial exposure. Although
there can be no assurance that such insurance will be sufficient to mitigate
all
damages, claims or contingencies, we believe that our insurance provides
reasonable coverage for known asserted or unasserted claims. In the event we
sustain a loss from a claim and the insurance carrier disputed coverage or
coverage limits, we may record a charge in a different period than the recovery,
if any, from the insurance carrier.
Calpine
Bankruptcy
Calpine
Corporation and certain of its subsidiaries filed for protection under the
federal bankruptcy laws in the Court on December 20, 2005. Calpine Energy
Services, L.P., which filed for bankruptcy, has continued to make the required
deposits into the Company’s margin account and to timely pay for natural gas
production it purchases from the Company’s subsidiaries under various natural
gas supply agreements. As part of the Acquisition, Calpine and the Company
entered into a Transition Services Agreement, pursuant to which services were
to
be provided to the Company through July 6, 2006. Calpine and certain of its
subsidiaries have generally continued to provide the services requested by
the
Company under the Transition Services Agreement. Additionally, Calpine Producer
Services, L.P., which filed for bankruptcy, generally is performing its
obligations under the Marketing and Services Agreement with the
Company.
There
remains the possibility, however, that there will be issues between the Company
and Calpine that could amount to material contingencies in relation to the
Purchase and Sale Agreement and interrelated agreements concurrently executed
therewith, dated July 7, 2005, by and among Calpine, the Company, and various
other signatories thereto (collectively, the “Purchase Agreement”), including
unasserted claims and assessments with respect to (i) the still pending Purchase
Agreement and the amounts that will be payable in connection therewith, (ii)
whether or not Calpine and its affiliated debtors will, in fact, perform their
remaining obligations in connection with the Purchase Agreement; and (iii)
the
ultimate disposition of the remaining Non-Consent Properties (and related
royalty revenues). Calpine has specific obligations to the Company under the
Purchase Agreement relating to these matters, and also has “further assurances”
duties to the Company under the Purchase Agreement.
In
addition, as to certain of the other oil and natural gas properties we purchased
from Calpine in the Acquisition and for which payment was made on July 7, 2005,
we will seek additional documentation from Calpine to eliminate any open issues
in our title or resolve any issues as to the clarity of our ownership.
Requests for additional documentation are customary in connection with
transactions similar to the Acquisition. In the Acquisition, certain of
these properties require ministerial governmental action approving us as
qualified assignee and operator, which is typically required even though in
most
cases Calpine has already conveyed the properties to us free and clear of
mortgages and liens in favor of Calpine’s creditors. As to certain other
properties, the documentation delivered by Calpine at closing under the Purchase
Agreement was incomplete. We remain hopeful that we will continue to work
cooperatively with Calpine to secure these ministerial governmental approvals
and to accomplish the curative corrections for all of these properties. In
addition, as to all properties acquired by us in the Acquisition, Calpine
contractually agreed to provide us with such further assurances as we may
reasonably request. Nevertheless, as a result of Calpine’s bankruptcy filing, it
remains uncertain as to whether Calpine will respond cooperatively. If Calpine
does not fulfill its contractual obligations and does not complete the
documentation necessary to resolve these issues, we will pursue all available
remedies, including but not limited to a declaratory judgment to enforce our
rights and actions to quiet title. After pursuing these matters, if we
experience a loss of ownership with respect to these properties without
receiving adequate consideration for any resulting loss to us, an outcome our
management considers to be remote, then we could experience losses which could
have a material adverse effect on our financial condition, statement of
operations and cash flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Court seeking the entry of an order authorizing Calpine to
assume certain oil and gas leases Calpine has previously sold or agreed to
sell
to us in the Acquisition, to the extent those leases constitute “unexpired
leases of non-residential real property” and were not fully transferred to us at
the time of Calpine’s filing for bankruptcy. According to this motion, Calpine
filed the motion in order to avoid the automatic forfeiture of any interest
it
may have in these leases by operation of a statutory deadline. Calpine’s motion
did not request that the Court determine whether these properties belong to
us
or Calpine, but we understand it was meant to allow Calpine to preserve and
avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may
possess, if any, in these oil and gas leases. We dispute Calpine’s
contention that it may have an interest in any significant portion of these
oil
and gas leases and intend to take the necessary steps to protect all of our
rights and interest in and to the leases. On July 7, 2006, we filed an objection
in response to Calpine’s motion, wherein we asserted that oil and gas leases
constitute interests in real property that are not subject to “assumption” under
the Bankruptcy Code. The objection also requested that (a) the Court eliminate
from the order certain Federal offshore leases from the Calpine motion because
these properties were fully conveyed to us in July 2005, and the Minerals
Management Service has subsequently recognized us as owner and operator of
these
properties, and (b) any order entered by the Court be without prejudice to,
and
fully preserve our rights, claims and legal arguments regarding the
characterization and ultimate disposition of the remaining described oil and
gas
properties. In our objection, we also urged the Court to require the parties
to
promptly address and resolve any remaining issues under the pre-bankruptcy
definitive agreements with Calpine and proposed to the Court that the parties
seek arbitration (or at least mediation) to complete the following:
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·
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Calpine’s
conveyance of the Non Consent Properties to
us;
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·
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Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreements with respect to
certain of the oil and gas properties for which we have already paid
Calpine; and
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·
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Resolution
of the final amounts we are to pay Calpine, which we have concluded
are
approximately $80 million, consisting of roughly $68 million for
the Non
Consent Properties and approximately $12 million in other true-up
payment
obligations.
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At
a
hearing held on July 12, 2006, the Court in Calpine Corporation’s bankruptcy
took the following steps:
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·
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In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Department
of
Interior) and the State of California (and managed by the California
State
Lands Commission). Calpine and the Department of Justice agreed to
an
extension of the existing deadline to November 15, 2006 to assume
such Oil
and Gas Leases under Section 365 of the Bankruptcy Code, to the extent
the
Oil and Gas Leases are leases subject to Section 365. The effect
of these
actions is to render our objection inapplicable at this time;
and
|
|
·
|
The
Court also encouraged Calpine and us to arrive at a business solution
to
all remaining issues including approximately $68 million payable
to
Calpine for conveyance of the Non Consent Properties.
|
On
August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts and unliquidated damages in amounts that can
not
presently be determined.
We
continue to work with Calpine on a cooperative and expedited basis toward
resolution of unresolved conveyance of properties and post-closing adjustments
under the Purchase Agreement.
Other
than
with
respect to the risk factors below, there have been no material changes in our
risk factors from those disclosed in Item 1A of our Annual Report on Form 10-K
for the year ended December 31, 2005. The
following risk factors were disclosed on the Form 10-K and have been updated
as
of June 30, 2006.
Calpine’s
recent bankruptcy filing may adversely affect us in several
respects.
Calpine,
its creditors and interest holders may challenge the fairness of some or all
of
the Acquisition.
Calpine
and certain of its subsidiaries (the “Debtors”) filed for protection under the
federal bankruptcy laws in the Court on December 20, 2005 (the “Petition
Date”). Calpine, its creditors or interest holders may bring an action under the
Bankruptcy Code or relevant state fraudulent conveyance laws asserting that
Calpine’s transfer of its domestic oil and natural gas business to us (as either
the initial transferee or the immediate or mediate transferee from the initial
transferee) should be voided or set aside as a fraudulent transfer. To prevail
in such a legal action, Calpine, its creditors or interest holders would be
required to prove that Calpine either:
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·
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Transferred
its domestic oil and natural gas business to us with the intent of
hindering, delaying or defrauding its current or future creditors;
or
|
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·
|
As
of July 7, 2005 (the date of the closing of the Acquisition),
(a) received less than reasonably equivalent value for the business,
and (b) was insolvent, became insolvent as a result of such transfer,
was engaged in a business or transaction or was about to engage in
a
business or transaction for which any property remaining was unreasonably
small, or intended to incur or believed it would incur debts that
would be
beyond its ability to pay as such debts matured.
|
Our
primary defense against such a legal challenge rests on the extensive
negotiations leading up to, and the market pricing mechanisms incorporated
within the terms of the Acquisition. Nonetheless, if after a trial on the
merits, the Court were to determine that the Debtors have met their burden
of
proof, it could void the transfer or take other actions against us, including
(i) setting aside the Acquisition and returning our purchase price and give
us a
first lien on all the properties and assets we purchased in the Acquisition
or
(ii) sustaining the Acquisition subject to our being required to pay the
Debtors the amount, if any, by which the fair value of the business transferred,
as determined by the Court as of July 7, 2005, exceeded the purchase price
determined and paid in July 2005. If the Court should so rule, a setting
aside of the Acquisition would be materially detrimental to us in that
substantially all our properties would be returned to Calpine, subject to our
right (as a good faith transferee) to retain a lien in our favor to secure
the
return of the purchase price we paid for the properties. Additionally, if the
Court should so rule, any requirement to pay an increased purchase price could
adversely affect us depending on the amount we might be required to
pay.
The
bankruptcy proceeding may prevent, frustrate or delay our ability to receive
record legal title to certain properties originally determined to be Non-Consent
Properties which we are entitled to receive under the Purchase
Agreement.
At
the
closing of the Acquisition, Calpine agreed to sell but retained title to certain
domestic oil and gas properties, subject to obtaining various third party
consents or waivers of preferential purchase rights in order to effect transfer
of title. In July 2005, as part of the transactions undertaken in connection
with closing the Acquisition, we accepted possession of and have since been
operating all of the properties for which Calpine retained record legal title.
We withheld approximately $75 million from the aggregate purchase price, which
was the allocated dollar amount under the Purchase Agreement for the remaining
properties. Subsequent to the closing of the Acquisition, with the exception
of
the properties subject to the preferential right to purchase, we obtained
substantially all of the consents to assign for all of these remaining
properties for which consents were actually required. Prior to the Calpine
bankruptcy, we were prepared to consummate the assignments of these remaining
properties, except those subject to the preferential purchase right to purchase.
The PV-10 value of these properties at December 31, 2005 was approximately
$72.4 million. Based on our internal calculations, we estimate the PV-10 value
of these properties as of June 30, 2006 to be approximately $63.7 million.
We
are prepared to pay Calpine the retained portion of the original purchase price,
approximately $68 million, and approximately $12 million in other true-up
payment obligations, all upon our receipt from Calpine of record title, free
of
any encumbrance, for that portion of these properties which are the Non Consent
Properties, subject to appropriate adjustment for the net revenues and expenses
through December 15, 2005. If the assignment of any remaining properties
(including any leases) does not occur, the portion of the purchase price we
held
back pending consent or waiver will be retained by us and will be available
to
us for general corporate purposes.
The
bankruptcy proceeding may prevent, frustrate or delay our ability to receive
corrective documentation from Calpine for certain properties that we bought
from
Calpine and paid for, in cases where Calpine delivered incomplete documentation,
including documentation related to certain ministerial governmental
approvals.
Certain
of the properties we purchased from Calpine and paid Calpine for on July 7,
2005, require certain additional documentation, depending on the particular
facts and circumstances surrounding the particular properties involved, such
documentation to be delivered by Calpine to quiet title related to our ownership
of these properties. Certain of these properties are subject to ministerial
governmental action approving us as qualified assignee and operator, even though
in most cases there had been a conveyance by Calpine and release of mortgages
and liens by Calpine’s creditors. For certain other properties, the
documentation delivered by Calpine at closing was incomplete. While we remain
hopeful that we will continue to work cooperatively with Calpine to secure
these
ministerial governmental approvals and accomplish the curative corrections
for
all of these properties for which we paid Calpine for, all of the same being
covered, we believe, by the further assurances provision of the Purchase
Agreement, the exact details for each property involved and how, when and if
this will be able to be secured or accomplished continue to remain uncertain
at
this early stage of Calpine’s bankruptcy.
Additionally,
on June 29, 2006, Calpine filed a motion in connection with its pending
bankruptcy proceeding seeking entry of an order authorizing Calpine to assume
certain oil and natural gas leases which Calpine previously sold or agreed
to
sell to us in the Acquisition, to the extent those leases constitute “unexpired
leases of non-residential real property” and were not fully transferred to us at
the time of Calpine’s filing for bankruptcy. According to this motion, Calpine
filed it to avoid the automatic forfeiture of any interest it might have in
these leases by operation of a statutory deadline. Calpine’s motion did not
request that the Court determine whether these properties belong to us or to
Calpine. Generally, oil and gas leases are regarded as real property and not
leases of real property despite their being called leases. If Calpine
successfully convinces the Court that the oil and natural gas leases are
“unexpired leases of non-residential real property,” subject to its obligations
under the Purchase Agreement, Calpine could require that we take further action
or pay further consideration to complete the assignments of these interests
or could retain the leases.
Any
failure to complete the corrective action necessary to remove title deficiencies
with respect to certain of these properties, including failure by Calpine to
deliver corrective documentation or failure of the Court to require Calpine
to
deliver such corrective documentation, could result in a material adverse effect
on us if we are not able to receive any offsetting refund of the portion of
the
purchase price attributable to the properties or if we are required to pay
additional consideration.
We
have expended and may continue to expend significant resources in connection
with Calpine’s bankruptcy.
We
have
expended and may continue to expend significant resources in connection with
Calpine’s bankruptcy. These resources include our increased costs for lawyers,
consultant experts and related expenses, as well as lost opportunity costs
associated with our dedicating internal resources to these matters. If we
continue to expend significant resources and our management is distracted from
the operational matters by the Calpine bankruptcy, our business, results of
operations, financial position or cash flows could be adversely
affected.
Operating
hazards, natural disasters or other interruptions of our operations could result
in potential liabilities, which may not be fully covered by our
insurance.
The
oil
and natural gas business involves certain operating hazards such
as:
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·
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Uncontrollable
flows of oil, natural gas or well
fluids
|
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·
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Hurricanes,
tropical storms, earthquakes, mud slides, and
flooding;
|
The
occurrence of one of the above may result in injury, loss of life, suspension
of
operations, environmental damage and remediation and/or governmental
investigations and penalties.
In
addition, our operations in California are especially susceptible to damage
from
natural disasters such as earthquakes and fires and involve increased risks
of
personal injury, property damage and marketing interruptions. Any of these
operating hazards could cause serious injuries, fatalities or property damage,
which could expose us to liabilities. The payment of any of these liabilities
could reduce, or even eliminate, the funds available for exploration,
development, and acquisition, or could result in a loss of our properties.
Our
insurance policies provide limited coverage for losses or liabilities relating
to pollution, with broader coverage for sudden and accidental occurrences.
Our
insurance might be inadequate to cover our liabilities. For example, we are
not
fully insured against earthquake risk in California because of high premium
costs. Insurance covering earthquakes or other risks may not be available at
premium levels that justify its purchase in the future, if at all. In addition,
we are subject to energy package insurance coverage limitations related to
any
single named windstorm. The insurance market in general and the energy insurance
market in particular have been difficult markets over the past several years.
Insurance costs are expected to continue to increase over the next few years
and
we may decrease coverage and retain more risk to mitigate future cost increases.
If we incur substantial liability and the damages are not covered by insurance
or are in excess of policy limits, or if we incur liability at a time when
we
are not able to obtain liability insurance, then our business, results of
operations, financial condition, and cash flows could be materially adversely
affected.
Environmental,
health, and safety liabilities could adversely affect our financial
condition.
The
oil
and natural and natural gas business is subject to environmental, health and
safety hazards, such as oil spills, natural gas leaks and ruptures and
discharges of petroleum products and hazardous substances, and historic disposal
activities. These hazards could expose us to material liabilities for property
damages, personal injuries or other environmental, health and safety harms,
including costs of investigating and remediating contaminated properties. In
addition, we also may be liable for environmental damages caused by the previous
owners or operators of properties we have purchased or are currently operating.
A variety of stringent federal, state and local laws and regulations govern
the
environmental aspects of our business and impose strict requirements for, among
other things:
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Well
drilling or work over, operation and
abandonment;
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·
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Financial
assurance under the Oil Pollution Act of 1990;
and
|
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Controlling
air, water and waste emissions.
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Any
noncompliance with these laws and regulations could subject us to material
administrative, civil or criminal penalties or other liabilities. Additionally,
our compliance with these laws may, from time to time, result in increased
costs
to our operations or decreased production, and may affect our costs of
acquisitions. We are unable to predict the ultimate cost of complying with
these
regulations.
In
addition, environmental laws may, in the future, cause a decrease in our
production or cause an increase in our costs of production, development or
exploration. Pollution and similar environmental risks generally are not fully
insurable.
Some
of
our California properties have been in operation for a substantial length of
time, and current or future local, state and federal environmental and other
laws and regulations may require substantial expenditures to remediate the
properties or to otherwise comply with these laws and regulations. A variety
of
existing laws, rules and guidelines govern activities that can be conducted
on
our properties and other existing or future laws, rules and guidelines could
prohibit or limit our operations and our planned activities for
properties.
Under
our
Purchase Agreement with Calpine, we are responsible for environmental claims
prior to the acquisition and we have no indemnification from Calpine related
to
those claims.
Item
2.
Unregistered Sales of Equity Securities and Use of
Proceeds
Issuance
of Unregistered Securities
None.
Item
3.
Defaults Upon Senior Securities
None.
Item
4. Submission
of Matters to a Vote of Security Holders
On
June
14, 2006 the Company held its Annual Meeting of Shareholders. At the meeting,
shareholders voted on election of all of our directors to serve until the next
annual meeting of shareholders. The following is a summary of the votes on
this
item:
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Votes
For
|
|
Votes
Withheld
|
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B.A.
"Bill" Berilgen
|
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38,293,539
|
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80,173
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Richard
W. Beckler
|
|
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37,771,038
|
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602,674
|
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Donald
D. Patteson, Jr.
|
|
|
37,771,038
|
|
|
602,674
|
|
D.
Henry Houston
|
|
|
37,767,038
|
|
|
606,674
|
|
G.
Louis Graziadio
|
|
|
33,221,797
|
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5,161,915
|
|
Rosetta
reported on Form 8-K during the quarter covered by this report all information
required to be reported on such form.
31.1 Certification
of Periodic Financial Reports by B.A. Berilgen in satisfaction of Section 302
of
the Sarbanes-Oxley Act of 2002
31.2 Certification
of Periodic Financial Reports by Michael J. Rosinski in satisfaction of Section
302 of the Sarbanes-Oxley Act of 2002
32.1 Certification
of Periodic Financial Reports by B.A. Berilgen and Michael J. Rosinski in
satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C.
Section 1350
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 thereunto
duly authorized.
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Date: August
14, 2006 |
|
/s/ Michael
J. Rosinski |
|
Michael J. Rosinski |
|
Executive
Vice
President and Chief Financial Officer |
|
(Duly
authorized and Principal Financial
Officer) |
ROSETTA
RESOURCES INC.
Exhibit
Number
|
|
Description
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