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
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For
The Quarterly Period Ended March
31,2007
OR
¨
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Transition
Report Pursuant To Section 15(d) of The Securities Exchange Act
of
1934
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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
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(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
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(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
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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, $.001 par value per share,
outstanding as of May 4, 2007 was 50,771,054.
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3
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3
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16
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20
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20
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21
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21
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23
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23
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23
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23
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23
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24
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25
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26
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Rule
13a-14(a) Certification executed by B.A. Berilgen
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Rule
13a-14(a) Certification executed by Michael J. Rosinski
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Section
1350 Certification
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Item
1. Financial Statements
Rosetta
Resources Inc.
Consolidated
Balance Sheet
(In
thousands, except share amounts)
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March
31,
2007
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December
31,
2006
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(Unaudited)
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Assets
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|
|
|
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Current
assets:
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|
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Cash
and cash equivalents
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$ |
50,907
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$ |
62,780
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Accounts
receivable
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|
36,774
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36,408
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Derivative
instruments
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122
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20,538
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Deferred
income taxes
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3,628
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-
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Prepaid
expenses
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19,298
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8,761
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Other
current assets
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3,444
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2,965
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Total
current assets
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114,173
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131,452
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Oil
and natural gas properties, full cost method, of which $44.1 million
at
March 31, 2007 and $37.8 million at December 31, 2006 were excluded
from
amortization
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1,290,739
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|
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1,223,337
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Other
fixed assets
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4,888
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4,562
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1,295,627
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1,227,899
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Accumulated
depreciation, depletion, and amortization
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(175,533 |
) |
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(145,289 |
) |
Total
property and equipment, net
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1,120,094
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1,082,610
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Deferred
loan fees
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|
3,080
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3,375
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Other
assets
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1,105
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1,968
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Total
other assets
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4,185
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5,343
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Total
assets
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$ |
1,238,452
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|
$ |
1,219,405
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Liabilities
and Stockholders' Equity
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Current
liabilities:
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Accounts
payable
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$ |
25,687
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$ |
23,040
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Accrued
liabilities
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49,392
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43,099
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Royalties
payable
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10,811
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9,010
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Derivative
instruments
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9,622
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-
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Prepayment
on gas sales
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18,590
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17,868
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Deferred
income taxes
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|
46
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|
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7,743
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Total
current liabilities
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114,148
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100,760
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Long-term
liabilities:
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Derivative
instruments
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17,753
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11,014
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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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11,262
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10,253
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Deferred
income taxes
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|
40,895
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|
35,089
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Total
liabilities
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424,058
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397,116
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Commitments
and contingencies (Note 8)
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Stockholders'
equity:
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Common
stock, $0.001 par value; authorized 150,000,000 shares; issued
50,427,523
shares and 50,405,794 shares at March 31, 2007 and December 31,
2006, respectively
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50
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50
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Additional
paid-in capital
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756,809
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755,343
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Treasury
stock, at cost; 88,887 and 85,788 shares at March 31, 2007 and
December
31, 2006, respectively
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(1,620 |
) |
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(1,562 |
) |
Accumulated
other comprehensive (loss) income
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(16,979 |
) |
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6,315
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Retained
earnings
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76,134
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62,143
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Total
stockholders' equity
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814,394
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822,289
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Total
liabilities and stockholders' equity
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$ |
1,238,452
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|
$ |
1,219,405
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The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Operations
(In
thousands, except per share amounts)
(Unaudited)
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|
Three
Months Ended
March
31,
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|
2007
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2006
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Revenues:
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Natural
gas sales
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$ |
69,161
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$ |
56,735
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Oil
sales
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6,635
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7,809
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Total
revenues
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75,796
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64,544
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Operating
Costs and Expenses:
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Lease
operating expense
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8,796
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9,558
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Depreciation,
depletion, and amortization
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30,551
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24,067
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Treating
and transportation
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|
763
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|
895
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Marketing
fees
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|
663
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624
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Production
taxes
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|
985
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1,697
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General
and administrative costs
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8,069
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9,251
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Total
operating costs and expenses
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49,827
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46,092
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Operating
income
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25,969
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18,452
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Other
(income) expense
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Interest
expense, net of interest capitalized
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4,370
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4,132
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Interest
income
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|
(972 |
) |
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|
(1,137 |
) |
Other
(income) expense, net
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|
-
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|
25
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Total
other expense
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3,398
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|
3,020
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|
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Income
before provision for income taxes
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|
22,571
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|
|
|
15,432
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Provision
for income taxes
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|
8,580
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|
|
|
5,906
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|
Net
income
|
|
$ |
13,991
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|
|
$ |
9,526
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|
|
|
|
|
|
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Earnings
per share:
|
|
|
|
|
|
|
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Basic
|
|
$ |
0.28
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|
|
$ |
0.19
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Diluted
|
|
$ |
0.28
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|
$ |
0.19
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Weighted
average shares outstanding:
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Basic
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|
50,325
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|
50,121
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Diluted
|
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|
50,483
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|
50,355
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The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Cash Flows
(In
thousands)
(Unaudited)
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|
Three
Months Ended
March
31,
|
|
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|
2007
|
|
|
2006
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
Net
income
|
|
$ |
13,991
|
|
|
$ |
9,526
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|
Adjustments
to reconcile net income to net cash from operating
activities
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
30,551
|
|
|
|
24,067
|
|
Deferred
income taxes
|
|
|
8,580
|
|
|
|
5,906
|
|
Amortization
of deferred loan fees recorded as interest expense
|
|
|
295
|
|
|
|
295
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|
Income
from unconsolidated investments
|
|
|
(47 |
) |
|
|
25
|
|
Stock
compensation expense
|
|
|
1,352
|
|
|
|
1,835
|
|
Change
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(366 |
) |
|
|
8,212
|
|
Income
taxes receivable
|
|
|
-
|
|
|
|
6,000
|
|
Other
assets
|
|
|
(10,720 |
) |
|
|
(4,160 |
) |
Accounts
payable
|
|
|
2,647
|
|
|
|
(1,753 |
) |
Accrued
liabilities
|
|
|
(2,285 |
) |
|
|
(2,857 |
) |
Royalties
payable
|
|
|
2,523
|
|
|
|
(6,081 |
) |
Net
cash provided by operating activities
|
|
|
46,521
|
|
|
|
41,015
|
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
|
Purchases
of property and equipment
|
|
|
(58,452 |
) |
|
|
(36,325 |
) |
Deposits
|
|
|
-
|
|
|
|
25
|
|
Other
|
|
|
3
|
|
|
|
111
|
|
Net
cash used in investing activities
|
|
|
(58,449 |
) |
|
|
(36,189 |
) |
Cash
flows from financing activities
|
|
|
|
|
|
|
|
|
Equity
offering transaction fees
|
|
|
-
|
|
|
|
267
|
|
Proceeds
from issuances of common stock
|
|
|
114
|
|
|
|
192
|
|
Purchases
of treasury stock
|
|
|
(59 |
) |
|
|
(1,246 |
) |
Other
|
|
|
-
|
|
|
|
(12 |
) |
Net
cash provided by (used in) financing activities
|
|
|
55
|
|
|
|
(799 |
) |
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash
|
|
|
(11,873 |
) |
|
|
4,027
|
|
Cash
and cash equivalents, beginning of period
|
|
|
62,780
|
|
|
|
99,724
|
|
Cash
and cash equivalents, end of period
|
|
$ |
50,907
|
|
|
$ |
103,751
|
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash disclosures:
|
|
|
|
|
|
|
|
|
Capital
expenditures included in accrued liabilities
|
|
$ |
4,397
|
|
|
$ |
2,249
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|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Notes
to Consolidated 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 to acquire
Calpine Natural Gas L.P., the domestic oil and natural gas business formerly
owned by Calpine Corporation and affiliates (“Calpine”). The Company acquired
Calpine Natural Gas L.P. in July 2005 (hereinafter, the “Acquisition”) and
together with all subsequently acquired oil and natural gas properties 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, the Lobo and
Perdido Trends in South Texas, the State Waters of 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 the Company’s Annual Report on Form
10-K for the year ended December 31, 2006.
Certain
reclassifications of prior year balances have been made to conform such amounts
to corresponding 2007 classifications. These reclassifications have
no impact on net income.
(2)
|
Summary
of Significant Accounting
Policies
|
The
Company has provided discussion of significant accounting policies, estimates
and judgments in its Annual Report on Form 10-K for the year ended December
31,
2006.
Principles
of Consolidation and Basis of Presentation. The accompanying
consolidated financial statements as of March 31, 2007 and December 31, 2006
and
for the three months ended March 31, 2007 and 2006 contain the accounts of
Rosetta Resources Inc. and its majority owned subsidiaries after eliminating
all
significant intercompany balances and transactions.
Recent
Accounting Developments
The
Fair Value Option for Financial Assets and Financial Liabilities. In
February 2007, the Financial Accounting Standards Board (“FASB”) issued
Statement of Financial Accounting Standards (“SFAS”) No. 159, “The
Fair Value Option For Financial Assets and Financial Liabilities - Including
an
Amendment of FASB Statement No. 115” (“SFAS” No. 159), which permits an entity
to choose to measure certain financial assets and liabilities at fair value.
SFAS No. 159 also revises provisions of SFAS No. 115 that apply to
available-for-sale and trading securities. This statement is effective for
fiscal years beginning after November 15, 2007. The Company has not yet
evaluated the potential impact of this standard.
Fair
Value Measurements. In September 2006, the FASB issued SFAS No.
157,“Fair Value Measurements” (“SFAS No. 157”), which addresses how
companies should measure fair value when companies are required to use a
fair
value measure for recognition or disclosure purposes under generally accepted
accounting principles (“GAAP”). As a result of SFAS No. 157, there is now a
common definition of fair value to be used throughout GAAP. SFAS No. 157
is
effective for financial statements issued for fiscal years beginning after
November 15, 2007, and interim periods within those years. The Company is
still
assessing the impact of this standard but does not expect the adoption of
this
standard 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 addresses the determination of whether tax
benefits claimed or expected to be claimed on a tax return should be recorded
in
the financial statements. Under FIN 48, the Company may recognize the tax
benefit from an uncertain tax position only if it is more likely than not
that
the tax position will be sustained on examination by the taxing authorities,
based on the technical merits of the position. The tax benefits recognized
in
the financial statements from such a position should be measured based on
the
largest benefit that has a greater than fifty percent likelihood of being
realized upon ultimate settlement. FIN 48 also provides guidance on
derecognition, classification, interest and penalties on income taxes,
accounting in interim periods and requires increased disclosures. The Company
adopted the provisions of FIN 48 on January 1, 2007. As a result of the
implementation of FIN 48, the Company did not have any unrecognized tax benefits
and there was no effect on the Company's consolidated financial
condition, results of operations or cash flows as a result of implementing
FIN 48. For additional information see Note 7 to the Consolidated Financial
Statements.
(3)
|
Property,
Plant and Equipment
|
The
Company’s total property, plant and equipment consist of the
following:
|
|
March
31,
2007
|
|
|
December
31,
2006
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$ |
1,237,939
|
|
|
$ |
1,170,223
|
|
Unproved
properties
|
|
|
31,517
|
|
|
|
35,178
|
|
Gas
gathering systems and compressor stations
|
|
|
21,283
|
|
|
|
17,936
|
|
Other
|
|
|
4,888
|
|
|
|
4,562
|
|
Total
|
|
|
1,295,627
|
|
|
|
1,227,899
|
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(175,533 |
) |
|
|
(145,289 |
) |
|
|
$ |
1,120,094
|
|
|
$ |
1,082,610
|
|
The
Company capitalizes internal costs directly identified with acquisition,
exploration and development activities. The Company capitalized $1.3 million
and
$0.8 million of internal costs for the three months ended March 31, 2007
and
2006, respectively.
Included
in the Company’s oil and natural gas properties are asset retirement obligations
of $14.5 million and $9.6 million as of March 31, 2007 and December 31, 2006,
respectively.
Oil
and
natural gas properties include costs of $44.1 million and $37.8 million at
March 31, 2007 and December 31, 2006, respectively, which were excluded from
capitalized costs being amortized. These amounts primarily represent
unproved properties and unevaluated exploration projects in which the Company
owns a direct interest. The increase in costs excluded during
2007 is primarily related to the increase in exploration activities
in Offshore and Texas State Waters.
The
Company’s ceiling test computation was calculated using hedge adjusted market
prices at March 31, 2007 which were based on a Henry Hub price of $7.34 per
MMBtu and a West Texas Intermediate oil price of $66.20 per Bbl (adjusted
for
basis and quality differentials). Cash flow hedges of natural gas production
in
place at March 31, 2007 increased the calculated ceiling value by approximately
$15 million (net of tax). There was no writedown recorded at March 31, 2007.
Due
to the volatility of commodity prices, should natural gas prices decline
in the
future, it is possible that a writedown could occur.
In
April
2007, the Company acquired properties located in the Sacramento Basin
from
Output Exploration, LLC and OPEX Energy, LLC at a total purchase price
of $40
million, subject to final adjustments.
(4)
|
Commodity
Hedging Contracts and Other
Derivatives
|
In
the
first quarter of 2007, the Company entered into additional 6,000 MMBtu per
day financial fixed price swaps with an average price of $8.11 per
MMBtu covering a portion of the Company’s 2007 production. The following
financial fixed price swaps were outstanding with associated notional volumes
and average underlying prices that represent hedged prices of commodities
at
various market locations at March 31, 2007:
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
(In
thousands)
|
|
2007
|
Swap
|
Cash
flow
|
|
|
55,327
|
|
|
|
15,215,000
|
|
|
|
$7.80
|
|
|
|
45%
|
|
|
|
(2,245 |
) |
2008
|
Swap
|
Cash
flow
|
|
|
49,909
|
|
|
|
18,266,616
|
|
|
|
$7.62
|
|
|
|
44%
|
|
|
|
(15,007 |
) |
2009
|
Swap
|
Cash
flow
|
|
|
26,141
|
|
|
|
9,541,465
|
|
|
|
$6.99
|
|
|
|
26%
|
|
|
|
(10,233 |
) |
|
|
|
|
|
|
|
|
|
43,023,081
|
|
|
|
|
|
|
|
|
|
|
$ |
(27,485 |
) |
(1)
Estimated based on net gas reserves presented in the December 31, 2006
Netherland, Sewell, & Associates, Inc. reserve report.
The
following costless collar transactions were outstanding with associated notional
volumes and contracted ceiling and floor prices that represent hedge prices
at
various market locations at March 31, 2007:
Settlement
Period
|
Derivative
Instrument
|
Hedge
Strategy
|
|
Notional
Daily Volume
MMBtu
|
|
|
Total
of Notional Volume
MMBtu
|
|
|
Average
Floor Price
MMBtu
|
|
Average
Ceiling Price
MMBtu
|
|
Total
of Proved Natural Gas Production Hedged (1)
|
|
|
Fair
Market Value
Gain
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
Costless
Collar
|
Cash
flow
|
|
|
10,000
|
|
|
|
2,750,000
|
|
|
$
|
7.19
|
|
|
$
|
10.03
|
|
|
|
8%
|
|
|
$ |
232
|
|
|
|
|
|
|
|
|
|
|
2,750,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
232
|
|
(1)
Estimated based on net gas reserves presented in the December 31, 2006
Netherland, Sewell, & Associates, Inc. reserve report.
The
Company’s current cash flow hedge positions are with counterparties who are
lenders in the Company’s credit facilities. This eliminates the need
for independent collateral postings with respect to any margin obligation
resulting from a negative change in fair market value of the derivative
contracts in connection with the Company’s hedge related credit
obligations. As of March 31, 2007, the Company made 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 March 31,
|
|
Natural
Gas
|
|
2007
|
|
|
2006
|
|
Quantity
settled (MMBtu)
|
|
|
5,499,500
|
|
|
|
4,950,000
|
|
Increase
in natural gas sales revenue (In thousands)
|
|
$ |
5,044
|
|
|
$ |
1,563
|
|
The
Company expects to reclassify losses of $5.9 million based on market pricing
as
of March 31, 2007 to earnings from the balance in accumulated other
comprehensive income (loss) on the Consolidated Balance Sheet during the
next
twelve months.
At
March
31, 2007, the Company had derivative assets of $0.1 million on the Consolidated
Balance Sheet. The Company also had derivative liabilities of $27.4
million of which $17.8 million is included in long-term liabilities on the
Consolidated Balance Sheet at March 31, 2007. The derivative
instrument assets and liabilities relate to commodity hedges that represent
the
difference between hedged prices and market prices on hedged volumes of the
commodities as of March 31, 2007. Hedging activities related to cash
settlements on commodities increased revenues by $5.0 million and $1.6 million
for the three months ended March 31, 2007 and 2006.
Gains
and
losses related to ineffectiveness and derivative instruments not designated
as
hedging instruments are included in other income (expense) and were immaterial
for the three months ended March 31, 2007 and 2006.
In
April
2007, the Company entered into two additional financial fixed price
swaps with prices ranging from $7.25 per MMBtu to $8.63 per MMBtu for a total
of
5,000 MMBtu per day covering a portion of the Company’s 2008
production.
(5)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (“ARO”) is as
follows:
|
|
Three
Months Ended March 31, 2007
|
|
|
|
(In
thousands)
|
|
ARO
as of January 1, 2007
|
|
$ |
10,689
|
|
Revision
of previous estimates
|
|
|
4,697
|
|
Liabilities
incurred during period
|
|
|
187
|
|
Accretion
expense
|
|
|
289
|
|
ARO
as of March 31, 2007
|
|
$ |
15,862
|
|
Of
the
total ARO, approximately $4.6 million is classified as a current liability
at
March 31, 2007.
The
Company’s credit facilities consist of a four-year senior secured revolving line
of credit (“Revolver”) of up to $400.0 million with a borrowing base of $325.0
million and a five-year $75.0 million second lien term loan.
On
March
31, 2007, 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 March 31, 2007. The Company was in
compliance with all covenants at March 31, 2007.
In
May
2007, the borrowing base of the Revolver was adjusted to $350.0
million. All amounts drawn under the Revolver are due and payable on
July 7, 2009. The principal balance associated with the second
lien term loan is due and payable on July 7, 2010.
The
Company did not have any unrecognized tax benefits and there was no effect
on
the Company’s consolidated financial condition, results of operations
or cash flows as a result of implementing FIN 48. The amount of
unrecognized tax benefits did not materially change as of March 31,
2007.
The
Company files a federal income tax return in the United States Federal
jurisdiction and various filings in several state and local jurisdictions.
The
Company began operations in 2005, and therefore is not subject to U.S. Federal,
state and local, or non-U.S. income tax examinations by tax authorities for
years before 2005.
Estimated
interest and penalties related to potential underpayment on any unrecognized
tax
benefits are classified as a component of tax expense in the Consolidated
Statement of Operations. As of the date of adoption of FIN 48, the Company
did
not have any accrued interest or penalties associated with any unrecognized
tax
benefits, nor was any interest expense recognized during the
quarter.
The
Company’s effective tax rate differs from the federal statutory rate primarily
due to state taxes, tax credits and other permanent differences. The
Company does not anticipate that total unrecognized tax benefits will
significantly change due to the settlement of audits and the expiration of
statute of limitations prior to March 31, 2008.
(8)
|
Commitment
and Contingencies
|
The
Company is party to various oil and natural gas litigation matters arising
out
of the normal course of business. 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 for 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 “Bankruptcy 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. Additionally, Calpine Producer Services,
L.P., which filed for bankruptcy, is under contract through June 30, 2007
with
the Company and is generally performing its obligations under the Marketing
and
Services Agreement.
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 by 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
Calpine will work cooperatively with the Company 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 Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had 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 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 Bankruptcy 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 natural gas leases. The Company disputes Calpine’s
contention that it may have an interest in any significant portion of these
oil
and natural 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 natural 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 Bankruptcy 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 all but three of these properties, and (b) any order entered
by the
Bankruptcy Court be without prejudice to, and fully preserve the Company’s
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 Bankruptcy 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 Bankruptcy
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 is approximately $79 million, consisting of roughly $68
million
for the Non-Consent Properties and approximately $11 million in
other
true-up payment obligations.
|
At
a
hearing held on July 12, 2006, the 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 Minerals
Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render the objection
of
the Company inapplicable at that time;
and
|
|
·
|
The
Bankruptcy 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 as well as unliquidated damages in amounts
that
can not 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.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases, these
parties have further extended this deadline time by stipulation. The deadline
was first extended to January 31, 2007, then was further extended to April
15,
2007 with respect to the MMS Oil and Gas Leases and April 30, 2007 with respect
to the CSLC Leases, and recently was further extended to September 15, 2007
with
respect to the MMS Oil and Gas Leases and July 15, 2007 with respect to the
CSLC
Leases. The Bankruptcy Court entered Orders related to the MMS Oil and Gas
Leases and CSLC Leases which included appropriate language that the Company
negotiated with Calpine for protection in this regard.
Recently,
Calpine sought and obtained an extension to June 20, 2007 from the Bankruptcy
Court for the period in which only Calpine, exclusively, may file its plan
of
reorganization. While there is no assurance that Calpine will file a plan
of
reorganization by this deadline, or that such a plan will be approved by
the
creditors and the Bankruptcy Court, the Company remains optimistic that the
issues involving conclusion of the remaining conveyances of the Non-Consent
Properties and obtaining the further assurances from Calpine under the Purchase
Agreement, including perhaps resolution of any and all claims, may occur
during
2007.
Calpine
recently requested Bankruptcy Court approval of a new credit facility which
would require it to grant liens to these new lenders in all of its assets,
including any interest it may still hold in any oil and natural gas properties
it obligated itself to convey to the Company under the Purchase Agreement.
The
Bankruptcy Court entered an Order approving Calpine’s ability to obtain this new
loan which includes appropriate language that the Company negotiated with
Calpine for the Company’s protection in this regard.
Furthermore,
there can be no assurance that Calpine, its creditors or other interest holders
will not challenge the fairness 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 challenges by the Calpine debtors
or their creditors to the overall fairness of the Acquisition would be
successful. The Company will take all necessary action to ensure the Company’s
rights under the Purchase agreement, the MMS Oil and Gas Leases, the CSLC
Leases
and the Bankruptcy Code are fully protected.
Arbitration
between Calpine Corp./RROLP and Pogo Producing
Company
On
September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico
oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course
of the sale, Pogo made three title defect claims on properties sold by Calpine
(valued at approximately $2.7 million in the aggregate, subject to a $0.5
million deductible assuming no reconveyance) claiming, that certain leases
subject to the sale had expired because of lack of production. Calpine had
undertaken without success to resolve this matter by obtaining ratifications
of
a majority of the questionable leases. Calpine filed for bankruptcy protection
before Pogo filed arbitration against it. Even though this is a retained
liability of Calpine, Calpine declined to accept the Company’s tender of defense
and indemnity when Pogo filed for arbitration against the
Company. The Company filed a motion to stay this arbitration under
the automatic stay provision of the Bankruptcy Code which motion was granted
by
the Bankruptcy Court on April 24, 2007 for a period of time of the earlier
of
fifteen months from the date of entry of the stay order or the effective
date of
a final order confirming Calpine’s plan of reorganization. This is a
retained liability by the Company and it is too early for management to
determine whether this matter will have any financial impact to the
Company.
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 March 31, 2007 and December 31, 2006 was $0.1 million.
The
Company does not expect that the outcome of 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 its 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 March 31, 2007
or
December 31, 2006 as the study is still in the preliminary stage.
The
Company’s total comprehensive income (loss) is shown below.
|
|
Three
Months Ended
March
31, 2007
|
|
|
Three
Months Ended
March
31, 2006
|
|
|
|
(In
thousands)
|
|
Accumulated
other comprehensive income (loss) - beginning of period
|
|
|
|
|
$ |
6,315
|
|
|
|
|
|
$ |
(50,731 |
) |
Net
income
|
|
|
13,991
|
|
|
|
|
|
|
|
9,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in fair value of derivative hedging instruments
|
|
|
(21,497 |
) |
|
|
|
|
|
|
51,750
|
|
|
|
|
|
Hedge
settlements reclassed to income
|
|
|
5,044
|
|
|
|
|
|
|
|
(1,563 |
) |
|
|
|
|
Tax
provision related to hedges
|
|
|
(6,841 |
) |
|
|
|
|
|
|
(19,071 |
) |
|
|
|
|
Total
other comprehensive (loss) income
|
|
|
(23,294 |
) |
|
|
(23,294 |
) |
|
|
31,116
|
|
|
|
31,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
(loss) income
|
|
|
(9,303 |
) |
|
|
|
|
|
|
40,642
|
|
|
|
|
|
Accumulated
other comprehensive loss
|
|
|
|
|
|
$ |
(16,979 |
) |
|
|
|
|
|
$ |
(19,615 |
) |
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 earnings per share 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:
|
|
Three
Months Ended
March
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Basic
weighted average number of shares outstanding
|
|
|
50,325
|
|
|
|
50,121
|
|
Dilution
effect of stock option and awards at the end of the
period
|
|
|
158
|
|
|
|
234
|
|
Diluted
weighted average number of shares outstanding
|
|
|
50,483
|
|
|
|
50,355
|
|
Stock
awards and shares excluded from diluted earnings per share due
to
anti-dilutive effect
|
|
|
435
|
|
|
|
103
|
|
(11)
|
Geographic
Area Information
|
The
Company owns oil and natural gas interests in eight main geographic areas
all
within the United States or its territorial waters. Geographic revenue and
property, plant and equipment information below are based on physical location
of the assets at the end of each period.
Oil
and Natural Gas Revenue
|
|
Three
Months Ended
March
31,
|
|
|
|
2007
(1)
|
|
|
2006
(1)
|
|
|
|
(In
thousands)
|
|
California
|
|
$ |
27,092
|
|
|
$ |
20,396
|
|
Lobo
|
|
|
24,876
|
|
|
|
15,408
|
|
Perdido
|
|
|
5,768
|
|
|
|
9,822
|
|
State
Waters
|
|
|
809
|
|
|
|
3,148
|
|
Other
Onshore
|
|
|
4,403
|
|
|
|
3,860
|
|
Gulf
of Mexico
|
|
|
5,474
|
|
|
|
9,526
|
|
Rockies
|
|
|
1,526
|
|
|
|
342
|
|
Mid-Continent
|
|
|
804
|
|
|
|
479
|
|
|
|
$ |
70,752
|
|
|
$ |
62,981
|
|
|
(1)
|
Excludes
the effects of hedging.
|
Oil
and Natural Gas Properties
|
|
March
31, 2007
|
|
|
December
31, 2006
|
|
|
|
(In
thousands)
|
|
California
|
|
$ |
445,501
|
|
|
$ |
435,167
|
|
Lobo
|
|
|
449,028
|
|
|
|
426,348
|
|
Perdido
|
|
|
59,673
|
|
|
|
52,702
|
|
State
Waters
|
|
|
34,453
|
|
|
|
26,922
|
|
Other
Onshore
|
|
|
106,222
|
|
|
|
102,734
|
|
Gulf
of Mexico
|
|
|
131,251
|
|
|
|
125,425
|
|
Rockies
|
|
|
52,527
|
|
|
|
44,455
|
|
Mid-Continent
|
|
|
12,084
|
|
|
|
9,584
|
|
Other
|
|
|
4,888
|
|
|
|
4,562
|
|
|
|
$ |
1,295,627
|
|
|
$ |
1,227,899
|
|
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This
report includes various “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of
the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical fact included or incorporated by reference in this
report are forward-looking statements, including without limitation all
statements regarding future plans, business objectives, strategies, expected
future financial position or performance, expected future operational position
or performance, budgets and projected costs, future competitive position,
or
goals and/or projections of management for future operations. In some cases,
you
can identify a forward-looking statement by terminology such as “may”, “will”,
“could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”,
“believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”,
the negative of such terms or variations thereon, or other comparable
terminology.
The
forward-looking statements contained in this report are largely based on
our
expectations for the future, which reflect certain estimates and assumptions
made by our management. These estimates and assumptions reflect our best
judgment based on currently known market conditions, operating trends, 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. As such, management’s assumptions about future
events may prove to be inaccurate. For a more detailed description of the
risks
and uncertainties involved, see Item 1A. Risk Factors in our Annual Report
on
Form 10-K for the year ended December 31, 2006 as updated by this report.
We do
not intend to publicly update or revise any forward-looking statements as
a
result of new information, future events, changes in circumstances, 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 that the events and circumstances they describe
will occur. Factors that could cause actual results to differ materially
from
those anticipated or implied in the forward-looking statements herein include,
but are not limited to:
·
|
The
supply and demand for oil, natural gas, and other products and
services;
|
·
|
The
price of
oil, natural gas, and other products and services;
|
·
|
Conditions
in the energy markets;
|
·
|
Changes
or advances in technology;
|
·
|
Currency
exchange rates and inflation;
|
·
|
The
availability and cost of relevant raw materials, goods and
services;
|
·
|
Future
processing volumes and pipeline
throughput;
|
·
|
Conditions
in the securities and/or capital
markets;
|
·
|
The
occurrence of property acquisitions or
divestitures;
|
·
|
Drilling
and exploration risks;
|
·
|
The
availability and cost of processing and
transportation;
|
·
|
Developments
in oil-producing and natural gas-producing
countries;
|
·
|
Competition
in the oil and natural gas
industry;
|
·
|
The
ability and willingness of our current or potential counterparties
or
vendors to enter into transactions with us and/or to fulfill
their
obligations to us;
|
·
|
Our
ability to access the capital markets on favorable terms or at
all;
|
·
|
Our
ability to obtain credit and/or capital in desired amounts and/or
on
favorable terms;
|
·
|
Present
and possible future claims, litigation and enforcement
actions;
|
·
|
Effects
of the application of applicable laws and regulations, including
changes
in such regulations or the interpretation thereof
;
|
·
|
Relevant
legislative or regulatory changes, including retroactive royalty
or
production tax regimes, changes in environmental regulation,
environmental
risks and liability under federal, state and foreign environmental
laws
and regulations;
|
·
|
General
economic conditions, either internationally, nationally or in
jurisdictions affecting our
business;
|
·
|
The
amount of resources expended in connection with Calpine’s bankruptcy,
including costs for lawyers, consultant experts and related expenses,
as
well as all lost opportunity costs associated with our internal
resources
dedicated to these matters;
|
·
|
Disputes
with mineral lease and royalty owners regarding calculation and
payment of
royalties;
|
·
|
The
weather, including the occurrence of any adverse weather conditions
and/or
natural disasters affecting our business;
and
|
·
|
Any
other factors that impact or could impact the exploration of
oil or
natural gas resources, including but not limited to 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.
|
ITEM
2. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
Overview
The
following discussion addresses material changes in the results of operations
for
the three months ended March 31, 2007, compared to the three months ended
March
31, 2006, and the material changes in financial condition since December
31,
2006. It is presumed that readers have read or have access to our
Annual Report on Form 10-K for the year ended December 31, 2006, which includes
disclosures regarding critical accounting policies as part of Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
We
continue to execute our strategy to increase value per share. The
following summarizes our performance for the first quarter of 2007 compared
to
the first quarter of 2006:
·
|
Net
income for the quarter increased 47% to $14.0
million;
|
·
|
Earnings
per share rose 47% to $0.28 per diluted
share;
|
·
|
Total
revenue, including the effects of hedging, increased 17% to $75.8
million;
|
·
|
Average
sales price, including the effects of hedging, declined 7% to $7.68
per
Mcfe;
|
·
|
Production
climbed 26% to 9.7 Bcfe;
|
·
|
Capital
expenditures increased over 60% to $62.8 million;
and
|
·
|
Drilled
45 gross wells with a success rate of
91%.
|
We
have
significantly grown our natural gas and oil production operations since our
July
2005 Acquisition and management believes it has the ability to continue growing
production by drilling already identified locations on our current existing
leases.
In
April
2007, the Company acquired properties located in the Sacramento Basin from
Output Exploration, LLC and OPEX Energy, LLC at a total purchase price
of $40
million, subject to final adjustments.
In
addition, in April 2007, we entered into two additional financial fixed price
swaps with prices ranging from $7.25 per MMBtu to $8.63 per MMBtu for a total
of
5,000 MMBtu per day covering a portion of our production.
Critical
Accounting Policies and Estimates
In
our
Annual Report on Form 10-K for the year ended December 31, 2006, 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, income taxes
and
stock-based compensation.
We
assess
the impairment for oil and natural gas properties for the full cost pool
quarterly using a ceiling test to determine if impairment is necessary. If
the
net capitalized costs of oil and natural gas properties exceed the cost center
ceiling, we are subject to a ceiling test write-down to the extent of such
excess. A ceiling test write-down is a charge to earnings and cannot be
reinstated even if the cost ceiling increases at a subsequent reporting date.
If
required, it would reduce earnings and impact shareholders’ equity in the period
of occurrence and result in a lower depreciation, depletion and amortization
expense in the future.
Our
ceiling test computation was calculated using hedge adjusted market prices
at
March 31, 2007 which were based on a Henry Hub price of $7.34 per MMBtu and
a
West Texas Intermediate oil price of $66.20 per Bbl (adjusted for basis and
quality differentials). Cash flow hedges of natural gas production in place
at
March 31, 2007 increased the calculated ceiling value by approximately $15
million (net of tax). There was no writedown recorded at March 31, 2007.
Due to
the volatility of commodity prices, should natural gas prices decline in
the
future, it is possible that a writedown could occur.
Results
of Operations
Revenues. Our
revenues are derived from the sale of our oil and natural gas production,
which
includes the effects of qualifying hedge contracts. Our revenues may
vary significantly from period to period as a result of changes in commodity
prices or volumes of production sold. Total revenue for the first
three months of 2007 was $75.8 million which is an increase of $11.3 million,
or
17%. Approximately, 91% of the first quarter revenue was attributable
to natural gas sales on total volumes of 9.7 Bcfe.
|
|
Three
Months Ended
March
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
%
Change
Increase/(Decrease)
|
|
|
|
(In
thousands, except per unit amounts)
|
|
|
|
|
Total
revenues
|
|
$ |
75,796
|
|
|
$ |
64,544
|
|
|
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
9.0
|
|
|
|
6.9
|
|
|
|
30 |
% |
Oil
(MBbls)
|
|
|
120.0
|
|
|
|
127.2
|
|
|
|
(6 |
%) |
Total
Equivalents (Bcfe)
|
|
|
9.7
|
|
|
|
7.7
|
|
|
|
26 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$ |
7.68
|
|
|
$ |
8.22
|
|
|
|
(7 |
%) |
Avg.
Gas Price per Mcf excluding Hedging
|
|
|
7.12
|
|
|
|
7.99
|
|
|
|
(11 |
%) |
Avg.
Oil Price per Bbl
|
|
|
55.29
|
|
|
|
61.39
|
|
|
|
(10 |
%) |
Avg.
Revenue per Mcfe
|
|
$ |
7.81
|
|
|
$ |
8.38
|
|
|
|
(7 |
%) |
Natural
Gas. For the three months ended March 31,
2007, natural gas revenue increased by $12.4 million, including the realized
impact of derivative instruments, from the comparable period in 2006, to
$69.2
million. The increase is primarily attributable to an increase in
production in the California and the Lobo regions resulting in an increase
of
$16.6 million and an increase in gains related to hedging activities of $3.5
million. Lower natural gas prices led to an approximate $7.7 million
decrease in natural gas revenues from the comparable period in
2006.
Crude
Oil. For the three months ended March 31,
2007, oil sales revenue was $6.6 million as compared to $7.8 million for
the
same period in 2006. This decrease of $1.2 million is due to both a
$6.10 per Bbl decrease in the realized oil price and a 7.2 MBbl decrease
in
production. The decrease in production is primarily the result of
natural declines in our Offshore area.
Operating
Expenses
|
|
Three
Months Ended
March
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
%
Change
Increase/(Decrease)
|
|
|
|
(In
thousands, except per unit amounts)
|
|
|
|
|
Lease
operating expense
|
|
$ |
8,796
|
|
|
$ |
9,558
|
|
|
|
(8 |
%) |
Depreciation,
depletion and amortization
|
|
|
30,551
|
|
|
|
24,067
|
|
|
|
27 |
% |
General
and administrative costs
|
|
$ |
8,069
|
|
|
$ |
9,251
|
|
|
|
(13 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$ |
0.91
|
|
|
$ |
1.24
|
|
|
|
(27 |
%) |
Avg.
DD&A per Mcfe
|
|
|
3.15
|
|
|
|
3.13
|
|
|
|
1 |
% |
Avg.
G&A per Mcfe
|
|
$ |
0.83
|
|
|
$ |
1.20
|
|
|
|
(31 |
%) |
Our
operating expenses are primarily related to the following items:
Lease
Operating Expense. Lease operating expense decreased $0.8
million for the three months ended March 31, 2007 compared to the three months
ended March 31, 2006. In 2006, we incurred $1.2 million more in
workover expenses which were associated with the Offshore area that were
not incurred in 2007.
Depreciation,
Depletion, and Amortization. Depreciation, depletion and
amortization expense increased $6.5 million from the same period in 2006
to
$30.6 million for the three months ended March 31, 2007. Depletion
expense for oil and gas properties is calculated using the unit of production
method, which amortizes the capitalized costs associated with the evaluated
properties based on the ratio of production volumes for the current period
to
the total remaining reserve volumes for the evaluated
properties. The increase for 2007 is due to the 26% increase in
production for the three months ended March 31, 2007 as compared to the three
months ended March 31, 2006.
General
and Administrative Costs. General and administrative costs were
$8.1 million for the three months ended March 31, 2007 as compared to $9.3
million for the same period in 2006. This decrease is primarily
associated with the costs incurred during the three months ended March 31,
2006
relating to legal, accounting and consulting fees associated with becoming
a
public entity, which were not incurred in the current reporting period for
2007. In addition, $0.5 million of the decrease is associated with
stock compensation expense which was $1.3 million for the three months ended
March 31, 2007 as compared to $1.8 million for the same period in
2006. For the first quarter of 2006, certain bonus stock awards
granted in July 2005 vested resulting in increased compensation expense for
2006
as compared to the first quarter of 2007.
Total
Other Expense
Other
expense includes interest expense, interest income and other income/expense,
net
and was comparable for the three months ended March 31, 2007 to the
corresponding period in 2006, with a $0.4 million increase. The
increase in other expense is the result of less interest income in the first
three months of 2007 to offset expenses as compared to 2006. The
interest income is earned on the cash balance, which was greater at March
31,
2006 than at March 31, 2007. Approximately $35.3 million was expended
primarily during the fourth quarter of 2006 to fund various asset
acquisitions.
Provision
for Income Taxes
The
effective tax rate for the three months ended March 31, 2007 was 38.0%, which
is
comparable to the tax rate for the three months ended March 31, 2006 of
38.3%. 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
primary source of capital and liquidity is our operating cash flow. We also
maintain a revolving line of credit which can be accessed as needed to
supplement operating cash flow.
Operating
Cash Flow. 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. The effects
of these derivative transactions on our natural gas revenue is discussed
above
under “Results of Operations – Natural Gas”. In addition, the
majority of our capital expenditures will be discretionary and could be
curtailed if our cash flows decline from expected levels.
Senior
Secured Revolving Line of Credit. BNP Paribas, in
July 2005 provided us with a senior secured revolving line of credit
concurrent with our acquisition of Calpine Corporation’s domestic oil and
natural gas business, (the “Acquisition”), in the amount of up to $400.0 million
(“Revolver”). This Revolver 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. 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. In May 2007, the borrowing base was adjusted to
$350.0
million. Initial amounts outstanding under the Revolver bore
interest, as amended, at specified margins over the London Interbank Offered
Rate (“LIBOR”) of 1.25% to 2.00%. These rates over LIBOR were
adjusted in May to be 1.00% to 1.75%. 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 SEC PV-10 pretax reserve value,
a
guaranty by all of our domestic subsidiaries, a pledge of 100% of the stock
of
domestic subsidiaries and a lien on cash securing the Calpine gas purchase
and
sale contract. 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 March 31, 2007, our current ratio was 2.6
to
1.0, as adjusted per current agreements and our leverage ratio was 1.2 to
1.0.
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
March 31, 2007. 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 March 31, 2007.
Second
Lien Term Loan. In July 2005, BNP Paribas provided us with
a second lien term loan in the amount of $100.0 million (“Term Loan”). 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 Term 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 Term Loan has been reduced to LIBOR plus
4.00%.
The Term 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 March 31, 2007. The revised principal
balance of the Term Loan is due and payable on July 7, 2010.
Cash
Flows
|
|
Three
Months Ended March 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Cash
flows provided by operating activities
|
|
$ |
46,521
|
|
|
$ |
41,015
|
|
Cash
flows used in investing activities
|
|
|
(58,449 |
) |
|
|
(36,189 |
) |
Cash
flows provided by (used in) financing activities
|
|
|
55
|
|
|
|
(799 |
) |
Net
(decrease) increase in cash and cash equivalents
|
|
$ |
(11,873 |
) |
|
$ |
4,027
|
|
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 and
general and administrative expenses. Net cash provided by operating
activities (“Operating Cash Flow”) continued to be a primary source of capital
and liquidity used to finance our capital expenditures in the first quarter
of
2007.
Cash
flows provided by operating activities increased by $5.5 million for the
three
months ended March 31, 2007 compared to the same period in 2006. The
increase in 2007 primarily resulted from higher oil and gas
production. Working capital at March 31, 2007 was less than $1
million compared to $30.7 million at December 31, 2006. This decrease
for the first quarter 2007 was largely driven by non-cash fair value changes
in
our derivative instruments as well as cash calls paid to fund on-going drilling
programs in the Offshore and Texas State Waters areas and for the payment
of ad
valorem taxes.
Investing
Activities. The primary driver of cash used in investing
activities is capital spending.
Cash
flows used in investing activities increased by $22.3 million for the three
months ended March 31, 2007 compared to the same period in
2006. During the three month period ended March 31, 2007, the Company
participated in the drilling of 45 gross wells with the majority of these
being
in the Rocky Mountains and the Lobo areas.
Financing
Activities. The primary driver of cash used in financing
activities is equity transactions.
Cash
flows provided by financing activities increased by $0.9 million for the
three
months ended March 31, 2007 compared to the same period in 2006. The
increase was primarily related to fewer repurchases of shares of common
stock. The shares were surrendered by certain employees to pay tax
withholding upon vesting of restricted stock awards. These
repurchases are not part of a publicly announced program to repurchase shares
of
our common stock, nor do we have a publicly announced program to repurchase
shares of common stock.
Capital
Expenditures
Our
capital expenditures for the three months ended March 31, 2007 increased
by
$24.2 million to $62.8 million over the comparable period in
2006. During the three months ended March 31, 2007, we participated
in the drilling of 45 gross wells with the majority of these being in the
Rocky
Mountains and the Lobo areas. Our positive Operating Cash Flow, along
with the availability under our revolving credit facility, is projected to
be sufficient to fund our budgeted capital expenditures for 2007, which are
currently projected to be $250.0 million.
Calpine
Bankruptcy
On
December 20, 2005 Calpine and certain of its subsidiaries filed for protection
under federal bankruptcy laws in the United States Bankruptcy Court of the
Southern District of New York (the “Bankruptcy Court”). The filing raises
certain concerns regarding aspects of our relationship with Calpine which
we
will continue to closely monitor as the Calpine bankruptcy proceeds. See
Part
II. Item 1. Legal Proceedings for further information regarding the Calpine
bankruptcy.
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, 2006. There have been no significant
changes in our market risk from what was disclosed in our Annual Report filed
on
Form 10-K for the year ended December 31, 2006.
Item
4. Controls and Procedures
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 March 31,
2007. Based on that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that, as of March 31, 2007, our disclosure controls
and procedures were effective in providing reasonable assurance that information
required to be disclosed by us in the reports filed or submitted by us under
the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the SEC’s rules and forms, and that such information is
accumulated and communicated to the Company’s management, including the Chief
Executive Officer and Chief Financial Officer, as appropriate, to allow timely
decisions regarding required disclosure.
There are
no changes in the Company’s internal control over financial reporting that
occurred during the most recent fiscal quarter that have materially affected,
or
are reasonable likely to materially affect, the Company’s internal control over
financial reporting.
Item
1. Legal
Proceedings
We
and
our subsidiaries are party to various oil and natural gas litigation matters
arising out of 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 Bankruptcy Court on December 20, 2005. Calpine
Energy Services, L.P., which filed for bankruptcy, has continued to make
the
required deposits into our margin account and to timely pay for natural gas
production it purchases from our subsidiaries under various natural gas supply
agreements. Additionally, Calpine Producer Services, L.P., which filed for
bankruptcy, is under contract through June 30, 2007 with us and is generally
performing its obligations under the Marketing and Services
Agreement.
There
remains the possibility, however, that there will be issues between us 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, us, 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 us under the Purchase Agreement
relating to these matters, and also has “further assurances” duties to us 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
by
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 Calpine will work cooperatively with us 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 Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had 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 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 Bankruptcy 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 natural
gas leases. We dispute Calpine’s contention that it may have an interest in any
significant portion of these oil and natural 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 natural gas leases constitute interests in real
property that are not subject to “assumption” under the Bankruptcy Code. In the
objection we also requested that (a) the Bankruptcy 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 all but three
of
these properties, and (b) any order entered by the Bankruptcy 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 our objection, we also urged
the
Bankruptcy 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 Bankruptcy 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 natural gas properties for
which we have already paid Calpine;
and
|
|
·
|
Resolution
of the final amounts we are to pay Calpine, which we have concluded
is
approximately $79 million, consisting of roughly $68 million for
the
Non-Consent Properties and approximately $11 million in other true-up
payment obligations.
|
At
a
hearing held on July 12, 2006, the 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 Minerals
Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render our
objection inapplicable at that time;
and
|
|
·
|
The
Bankruptcy 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 as well as 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.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases, these
parties have further extended this deadline time by stipulation. The deadline
was first extended to January 31, 2007, then was further extended to April
15,
2007 with respect to the MMS Oil and Gas Leases and April 30, 2007 with respect
to the CSLC Leases, and recently was further extended to September 15, 2007
with
respect to the MMS Oil and Gas Leases and July 15, 2007 with respect to the
CSLC
Leases. The Bankruptcy Court entered Orders related to the MMS Oil and Gas
Leases and CSLC Leases which included appropriate language that we negotiated
with Calpine for our protection in this regard.
Recently,
Calpine sought and obtained an extension to June 20, 2007 from the Bankruptcy
Court for the period in which only Calpine, exclusively, may file its plan
of
reorganization. While there is no assurance that Calpine will file a plan
of
reorganization by this deadline, or that such a plan will be approved by
the
creditors and the Bankruptcy Court, we remain optimistic that the issues
involving conclusion of the remaining conveyances of the Non-Consent Properties
and obtaining the further assurances from Calpine under the Purchase Agreement,
including perhaps resolution of any and all claims, may occur during
2007.
Calpine
recently requested Bankruptcy Court approval of a new credit facility which
would require it to grant liens to these new lenders in all of its assets,
including any interest it may still hold in any oil and natural gas properties
it obligated itself to convey to us under the Purchase Agreement. The Bankruptcy
Court entered an Order approving Calpine’s ability to obtain this new loan which
includes appropriate language that we negotiated with Calpine for our
protection in this regard.
Furthermore,
there can be no assurance that Calpine, its creditors or other interest holders
will not challenge the fairness of the Acquisition. For a number of reasons,
including our understanding of the process that Calpine followed in allowing
market forces to set the purchase price for the Acquisition, we believe that
it
is unlikely that any challenges by the Calpine debtors or their creditors
to the
overall fairness of the Acquisition would be successful. We will take all
necessary action to ensure our rights under the Purchase agreement, the MMS
Oil
and Gas Leases, the CSLC Leases and the Bankruptcy Code are fully
protected.
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,
2006.
Item
2. Unregistered Sales of Equity Securities and Use of Proceeds
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers
Period
|
|
Total
Number of Shares Purchased (1)
|
|
|
Average
Price Paid per Share
|
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans
or
Programs
|
|
|
Maximum
Number (or Approximate Dollar Value) of Shares that May yet Be
Purchased
Under the Plans or Programs
|
|
January
1 - January 31
|
|
|
82
|
|
|
$ |
18.76
|
|
|
|
-
|
|
|
|
-
|
|
February
1 - February 28
|
|
|
2,473
|
|
|
|
18.87
|
|
|
|
-
|
|
|
|
-
|
|
March
1 - March 31
|
|
|
544
|
|
|
|
19.52
|
|
|
|
-
|
|
|
|
-
|
|
(1)
|
All
of the shares repurchased were surrendered by employees to pay
tax
withholding upon the vesting of restricted stock awards. These
repurchases were not part of a publicly announced program to repurchase
shares of our common stock, nor do we have a publicly announced
program to
repurchase shares of our common
stock.
|
Issuance
of Unregistered Securities
None.
Item
3. Defaults Upon Senior Securities
None.
Item
4. Submission of Matters to a Vote of Security Holders
None.
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
|
Signatures
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant
has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
ROSETTA
RESOURCES INC.
|
|
By:
|
/s/
MICHAEL J. ROSINSKI
|
|
Michael
J. Rosinski
|
|
Executive
Vice President and Chief Financial Officer
|
|
|
|
|
(Duly
Authorized Officer and Principal Financial
Officer)
|
Date:
May
15, 2007
EXHIBIT
INDEX
Exhibit
Number
|
|
Description
|
|
|
Certification
of Periodic Financial Reports by B. A. Berilgen in satisfaction
of Section
302 of the Sarbanes-Oxley Act of 2002
|
|
|
Certification
of Periodic Financial Reports by Michael J. Rosinski in satisfaction
of
Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
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
|
26