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 September 30, 2008
OR
o
|
Transition
Report Pursuant To Section 13 or 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)
|
|
Delaware
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43-2083519
|
(State
or other jurisdiction of incorporation or organization)
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(I.R.S.
Employer Identification No.)
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717
Texas, Suite 2800, Houston, TX
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77002
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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
|
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 o
Indicate
by check mark whether the Registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting
company. See definitions of “large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange
Act of 1934.
Large
accelerated filer x
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Accelerated
filer o
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Non-Accelerated
filer o
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Smaller
Reporting Company o
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(Do
not check if smaller reporting
company)
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Securities Exchange Act of 1934). Yes o No x
The
number of shares of the registrant's Common Stock, $.001 par value per share,
outstanding as of November 3, 2008 was 51,744,778.
Part
I – Financial Information
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3
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15
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24
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25
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Part
II – Other Information
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25
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25
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26
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26
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27
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27
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28
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29
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PART
I. FINANCIAL INFORMATION
Item
1. Financial Statements
Rosetta
Resources Inc.
Consolidated
Balance Sheet
(In
thousands, except share amounts)
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September
30,
2008
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December
31,
2007
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(Unaudited)
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Assets
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Current
assets:
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Cash
and cash equivalents
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$ |
135,183 |
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$ |
3,216 |
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Accounts
receivable
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53,504 |
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55,048 |
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Derivative
instruments
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4,623 |
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3,966 |
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Prepaid
expenses
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5,550 |
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10,413 |
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Other
current assets
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4,068 |
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4,249 |
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Total
current assets
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$ |
202,928 |
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$ |
76,892 |
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Oil
and natural gas properties, full cost method, of which $32.0 million at
September 30, 2008 and $40.9 million at December 31, 2007 were excluded
from amortization
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1,752,569 |
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1,566,082 |
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Other
fixed assets
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7,738 |
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6,393 |
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1,760,307 |
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1,572,475 |
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Accumulated
depreciation, depletion, and amortization and impairment
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(649,007 |
) |
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(295,749 |
) |
Total
property and equipment, net
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1,111,300 |
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1,276,726 |
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Deferred
loan fees
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1,310 |
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2,195 |
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Other
assets
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1,567 |
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1,401 |
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Total
other assets
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2,877 |
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3,596 |
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Total
assets
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$ |
1,317,105 |
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$ |
1,357,214 |
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Liabilities
and Stockholders' Equity
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Current
liabilities:
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Accounts
payable
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$ |
36,995 |
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$ |
33,949 |
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Accrued
liabilities
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54,078 |
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64,216 |
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Royalties
payable
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24,065 |
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18,486 |
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Derivative
instruments
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518 |
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2,032 |
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Prepayment
on gas sales
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23,078 |
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20,392 |
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Deferred
income taxes
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1,529 |
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720 |
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Total
current liabilities
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140,263 |
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139,795 |
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Long-term
liabilities:
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Derivative
instruments
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3,371 |
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13,508 |
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Long-term
debt
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245,000 |
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245,000 |
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Asset
retirement obligation
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25,858 |
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18,040 |
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Deferred
income taxes
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46,730 |
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67,916 |
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Total
liabilities
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461,222 |
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484,259 |
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Commitments
and contingencies (Note 9)
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Stockholders'
equity:
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Preferred
stock, $0.001 par value; authorized 5,000,000 shares; no shares
issued in 2008 or 2007
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- |
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- |
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Common
stock, $0.001 par value; authorized 150,000,000 shares; issued 50,987,406
shares and 50,542,648 shares at September 30, 2008 and December 31, 2007,
respectively
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50 |
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50 |
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Additional
paid-in capital
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771,471 |
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762,827 |
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Treasury
stock, at cost; 151,476 and 109,303 shares at September 30, 2008 and
December 31, 2007, respectively
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(2,876 |
) |
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(2,045 |
) |
Accumulated
other comprehensive income (loss)
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461 |
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(7,225 |
) |
Retained
earnings
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86,777 |
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119,348 |
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Total
stockholders' equity
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855,883 |
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872,955 |
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Total
liabilities and stockholders' equity
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$ |
1,317,105 |
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$ |
1,357,214 |
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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
September
30,
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Nine
Months Ended
September
30,
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2008
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2007
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2008
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2007
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Revenues:
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Natural
gas sales
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$ |
114,308 |
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$ |
79,061 |
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$ |
362,894 |
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$ |
225,658 |
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Oil
sales
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15,728 |
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10,657 |
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49,941 |
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26,730 |
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Total
revenues
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130,036 |
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89,718 |
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412,835 |
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252,388 |
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Operating
Costs and Expenses:
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Lease
operating expense
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12,857 |
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11,912 |
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40,445 |
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33,274 |
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Depreciation,
depletion, and amortization
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46,951 |
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38,186 |
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150,103 |
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105,079 |
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Impairment
of oil and gas properties
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205,659 |
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- |
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205,659 |
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- |
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Treating
and transportation
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1,780 |
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1,412 |
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4,624 |
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3,057 |
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Marketing
fees
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840 |
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518 |
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2,602 |
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1,850 |
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Production
taxes
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2,336 |
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1,243 |
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11,528 |
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3,428 |
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General
and administrative costs
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15,419 |
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12,032 |
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41,042 |
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29,999 |
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Total
operating costs and expenses
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285,842 |
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65,303 |
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456,003 |
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176,687 |
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Operating
(loss) income
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(155,806 |
) |
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24,415 |
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(43,168 |
) |
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75,701 |
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Other
(income) expense
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Interest
expense, net of interest capitalized
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3,186 |
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4,332 |
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11,209 |
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13,382 |
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Interest
income
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(586 |
) |
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(240 |
) |
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(1,141 |
) |
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(1,469 |
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Other
(income) expense, net
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(40 |
) |
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(105 |
) |
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(170 |
) |
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(287 |
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Total
other expense
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2,560 |
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3,987 |
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9,898 |
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11,626 |
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(Loss)
income before provision for income taxes
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(158,366 |
) |
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20,428 |
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(53,066 |
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64,075 |
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Provision
for income taxes
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(58,991 |
) |
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7,715 |
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(20,495 |
) |
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24,280 |
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Net
(loss) income
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$ |
(99,375 |
) |
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$ |
12,713 |
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$ |
(32,571 |
) |
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$ |
39,795 |
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Earnings
per share:
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Basic
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$ |
(1.96 |
) |
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$ |
0.25 |
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$ |
(0.64 |
) |
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$ |
0.79 |
|
Diluted
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$ |
(1.96 |
) |
|
$ |
0.25 |
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$ |
(0.64 |
) |
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$ |
0.79 |
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Weighted
average shares outstanding:
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Basic
|
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|
50,813 |
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|
50,409 |
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|
50,636 |
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|
50,363 |
|
Diluted
|
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|
50,813 |
|
|
|
50,570 |
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|
50,636 |
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|
50,572 |
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Cash Flows
(In
thousands)
(Unaudited)
|
|
Nine
Months Ended
September
30,
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|
2008
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|
2007
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
Net
(loss) income
|
|
$ |
(32,571 |
) |
|
$ |
39,795 |
|
Adjustments
to reconcile net (loss) income to net cash from operating
activities
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|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
150,103 |
|
|
|
105,079 |
|
Impairment
of oil and gas properties
|
|
|
205,659 |
|
|
|
- |
|
Deferred
income taxes
|
|
|
(24,939 |
) |
|
|
24,195 |
|
Amortization
of deferred loan fees recorded as interest expense
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|
|
885 |
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|
885 |
|
Income
from unconsolidated investments
|
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|
(418 |
) |
|
|
(117 |
) |
Stock
compensation expense
|
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|
4,975 |
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|
4,090 |
|
Change
in operating assets and liabilities:
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Accounts
receivable
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|
1,544 |
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|
84 |
|
Other
current assets
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|
5,044 |
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|
(11,417 |
) |
Other
assets
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|
192 |
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|
331 |
|
Accounts
payable
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|
3,046 |
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|
12,267 |
|
Accrued
liabilities
|
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|
4,516 |
|
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|
3,636 |
|
Royalties
payable
|
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|
8,265 |
|
|
|
4,725 |
|
Net
cash provided by operating activities
|
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|
326,301 |
|
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|
183,553 |
|
Cash
flows from investing activities
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Acquisition
of oil and gas properties
|
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|
(29,570 |
) |
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|
(38,656 |
) |
Purchases
of property and equipment
|
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|
(167,629 |
) |
|
|
(205,310 |
) |
Disposals
of property and equipment
|
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|
27 |
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|
|
1,104 |
|
Other
|
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|
0 |
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|
25 |
|
Net
cash used in investing activities
|
|
|
(197,172 |
) |
|
|
(242,837 |
) |
Cash
flows from financing activities
|
|
|
|
|
|
|
|
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Borrowing
from revolving credit facility
|
|
|
- |
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|
|
10,000 |
|
Proceeds
from stock options exercised
|
|
|
3,669 |
|
|
|
571 |
|
Purchases
of treasury stock
|
|
|
(831 |
) |
|
|
(411 |
) |
Net
cash provided by financing activities
|
|
|
2,838 |
|
|
|
10,160 |
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease) in cash
|
|
|
131,967 |
|
|
|
(49,124 |
) |
Cash
and cash equivalents, beginning of period
|
|
|
3,216 |
|
|
|
62,780 |
|
Cash
and cash equivalents, end of period
|
|
$ |
135,183 |
|
|
$ |
13,656 |
|
|
|
|
|
|
|
|
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Supplemental
non-cash disclosures:
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|
|
|
|
|
|
|
Capital
expenditures included in accrued liabilities
|
|
$ |
23,316 |
|
|
$ |
28,575 |
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Notes
to Consolidated Financial Statements (unaudited)
(1)
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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. (and its partners) and the domestic oil and natural gas
business formerly owned by Calpine Corporation and affiliates (“Calpine”). The
Company acquired Calpine Natural Gas L.P. (and its partners) and Rosetta
Resources California, LLC, Rosetta Resources Rockies, LLC, Rosetta Resources
Offshore, LLC and Rosetta Resources Texas LP (and its partners) 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 North America. The
Company’s main operations are primarily concentrated in the Sacramento Basin of
California, the Rocky Mountains, the Lobo and Perdido Trends in South Texas, the
State Waters of Texas and the Gulf of Mexico.
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, 2007.
Certain
reclassifications of prior year balances have been made to conform them to the
current year presentation. These reclassifications have no impact on
net income.
(2)
|
Summary
of Significant Accounting Policies
|
The
Company has provided a discussion of significant accounting policies, estimates
and judgments in its Annual Report on Form 10-K for the year ended December 31,
2007.
Principles of
Consolidation. The accompanying consolidated financial
statements as of September 30, 2008 and December 31, 2007 and for the three and
nine months ended September 30, 2008 and 2007 contain the accounts of the
Company and its majority owned subsidiaries after eliminating all significant
intercompany balances and transactions.
Fair Value Measurements. In
September 2006, the Financial Accounting Standards Board (“FASB”) issued
Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value
Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value,
establishes a framework for measuring fair value and expands the related
disclosure requirements. SFAS No. 157 does not require any new fair
value measurements but may require some entities to change their measurement
practices. SFAS No. 157 is effective for financial statements issued
for fiscal years beginning after November 15, 2007, and interim periods within
those years. The FASB also issued FASB Staff Position (“FSP”) FAS 157-2
(“FSP No. 157-2”), which delayed the effective date of SFAS No. 157 for
nonfinancial assets and liabilities, except for items that are recognized or
disclosed at fair value in the financial statements on a recurring basis (at
least annually), until fiscal years beginning after November 15,
2008. Effective January 1, 2008, the Company partially adopted SFAS
No. 157 and has chosen to defer the implementation of SFAS No.157 for
nonfinancial assets and liabilities in accordance with FSP No. 157-2.
Accordingly, the Company will apply SFAS No. 157 to its nonfinancial assets and
liabilities that are disclosed or recognized at fair value on a nonrecurring
basis and other assets and liabilities in the first quarter of
2009. We are still in the process of evaluating the effect of SFAS
No. 157 on our nonfinancial assets and liabilities and therefore have not yet
determined the impact that it will have on our financial statements upon full
adoption in 2009. Nonfinancial assets and liabilities for which we have not yet
applied the provisions of SFAS No. 157 include our asset retirement
obligations. The adoption of SFAS No. 157 for financial assets and
liabilities did not have a significant effect on our consolidated financial
position, results of operations or cash flows. See Note 5 - Fair
Value Measurements.
The
Company also adopted SFAS No. 159, “The Fair Value Option for Financial Assets
and Financial Liabilities, Including an Amendment of SFAS No. 115” (“SFAS No.
159”) on January 1, 2008. SFAS No. 159 permits companies to choose to
measure financial instruments and certain other items at fair value that were
not previously required to be measured at fair value. The Company
elected not to present assets and liabilities at fair value that were not
required to be measured at fair value prior to the adoption of SFAS No.
159.
Recent
Accounting Developments
The
Hierarchy of Generally Accepted Accounting Principles. In
May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles” (“SFAS No. 162”), which identifies the sources of
accounting principles and the framework for selecting the principles used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with GAAP in the United States (the “GAAP
hierarchy”). SFAS No. 162 is effective 60 days following the
Securities and Exchange Commission’s (“SEC”) approval of the Public Company
Accounting Oversight Board (“PCAOB”) amendments to AU Section 411,
“The Meaning of Present Fairly in Conformity With Generally Accepted
Accounting Principles.” For pronouncements whose effective date is
after March 15, 1992, and for entities initially applying an accounting
principle after March 15, 1992 (except for EITF consensus positions issued
before March 16, 1992, which become effective in the hierarchy for initial
application of an accounting principle after March 15, 1993), an entity shall
follow this Statement. Any effect of applying the provisions of this
Statement shall be reported as a change in accounting principle in accordance
with FASB Statement No. 154, “Accounting Changes and Error
Corrections.” An
entity shall follow the disclosure requirements of that Statement, and
additionally, disclose the accounting principles that were used before and after
the application of the provisions of this Statement and the reason why applying
this Statement resulted in a change in accounting principle. The
Company does not expect the adoption of SFAS No. 162 to have a material impact
on the Company’s consolidated financial position, results of operations or cash
flows.
Disclosures about Derivative
Instruments and Hedging Activities. In March 2008, the
FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging
Activities – an Amendment of FASB Statement No. 133” (“SFAS No. 161”), which
is intended to improve financial reporting about derivative instruments and
hedging activities by requiring enhanced disclosures. This statement
is effective for fiscal years beginning after November 15, 2008. The
Company is currently evaluating the potential impact of SFAS No. 161 on the
Company’s consolidated financial statements.
Noncontrolling Interests in
Consolidated Financial Statements. In December 2007, the
FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial
Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No.
160”), which improves the relevance, comparability and transparency of the
financial information that a reporting entity provides in its consolidated
financial statements by establishing accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. This statement is effective for fiscal years beginning
after December 15, 2008. The Company does not expect the adoption of
SFAS No. 160 to have a material impact on the Company’s consolidated financial
position, results of operations or cash flows.
Business Combinations. In
December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS
No. 141R”), which creates greater consistency in the accounting and financial
reporting of business combinations. This statement is effective for
fiscal years beginning after December 15, 2008. The Company
does not expect the adoption of SFAS No. 141R to have a material impact on the
Company’s consolidated financial position, results of operations or cash
flows.
Derivative
Instruments. In September 2008, the FASB issued FSP FAS 133-1
and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An
Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and
Clarification of the Effective Date of FASB Statement No. 161” (“FSP FAS 133-1
and FIN 45-4”). This FSP amends FASB Statement No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” to require disclosures by
sellers of credit derivatives, including credit derivatives embedded in a hybrid
instrument. This FSP also amends FASB Interpretation No. 45, “Guarantor’s
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others,” to require an additional disclosure about
the current status of the payment/performance risk of a guarantee. Further, this
FSP clarifies the FASB’s intent about the effective date of SFAS No.161.
This FSP is effective for reporting periods (annual or interim) ending
after November 15, 2008. We do not expect this FSP to have a significant impact
on our consolidated financial position, results of operations or cash
flows.
Fair Value
Measurements. In October 2008, the FASB issued FSP FAS 157-3,
“Determining the Fair Value of a Financial Asset When the Market for That Asset
Is Not Active” (“FSP FAS 157-3”). This FSP clarifies the application of
SFAS No. 157 in a market that is not active and provides an example to
illustrate key considerations in determining the fair value of a financial asset
when the market for that financial asset is not active. This FSP was
effective upon issuance, including prior periods for which financial statements
have not been issued. We applied this FSP to financial assets measured at
fair value on a recurring basis at September 30, 2008. See Note 5 - Fair
Value Measurements. The adoption of FSP FAS 157-3 did not have a
significant impact on our consolidated financial position, results of operations
or cash flows.
Equity Method
Investments. In October 2008, the FASB issued Emerging Issues
Task Force (“EITF”) Issue No. 08-6, “Equity Method Investment Accounting
Considerations” (“EITF 08-6”). The objective of this issue is to clarify how to
account for certain transactions involving equity method investments. This issue
is effective on a prospective basis in fiscal years beginning on or after
December 15, 2008, and interim periods within those fiscal years. Earlier
application by an entity that has previously adopted an alternative accounting
policy is not permitted. We do not expect this issue to have a significant
impact on our consolidated financial position, results of operations or cash
flows.
(3)
|
Property,
Plant and Equipment
|
The
Company’s total property, plant and equipment consists of the
following:
|
|
September
30,
2008
|
|
|
December
31,
2007
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$ |
1,686,035 |
|
|
$ |
1,499,046 |
|
Unproved/unevaluated
properties
|
|
|
32,020 |
|
|
|
40,903 |
|
Gas
gathering systems and compressor stations
|
|
|
34,514 |
|
|
|
26,133 |
|
Other
|
|
|
7,738 |
|
|
|
6,393 |
|
Total
oil and natural gas properties
|
|
|
1,760,307 |
|
|
|
1,572,475 |
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(649,007 |
) |
|
|
(295,749 |
) |
Total
property and equipment, net
|
|
$ |
1,111,300 |
|
|
$ |
1,276,726 |
|
The
Company capitalizes internal costs directly identified with acquisition,
exploration and development activities. The Company capitalized $1.5 million and
$1.0 million of internal costs for the three months ended September 30, 2008 and
2007, respectively, and $4.3 million and $3.4 million for the nine months ended
September 30, 2008 and 2007, respectively.
Included
in the Company’s oil and gas properties are asset retirement costs of $23.0
million and $20.1 million as of September 30, 2008 and December 31, 2007,
respectively.
Oil and
gas properties include costs of $32.0 million and $40.9 million at September 30,
2008 and December 31, 2007, respectively, that 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.
Pursuant
to full cost accounting rules, the Company must perform a ceiling test each
quarter on its proved oil and gas assets within each separate cost
center. The Company’s ceiling test was calculated using hedge
adjusted market prices of gas and oil at September 30, 2008, which were based on
a Henry Hub price of $7.12 per MMBtu and a West Texas Intermediate oil price of
$96.37 per Bbl (adjusted for basis and quality differentials). Cash flow hedges
of natural gas production in place at September 30, 2008 increased the
calculated ceiling value by approximately $23 million (net of tax). Based
upon studies to date, and in coordination with the Company's independent reserve
engineers, the Company recognized a downward revision of 50-60 Bcfe of
proved reserves during the third quarter of 2008. Based upon this analysis
and the reserve revision, a write-down of $129.1 million (net of tax) was
recorded at September 30, 2008. It is possible that another
write-down of the Company's oil and gas properties could occur in the
future should natural gas prices continue to decline and/or the Company
experiences downward adjustments to the estimated proved reserves.
(4)
|
Commodity
Hedging Contracts and Other
Derivatives
|
The
Company has entered into financial fixed price swaps with prices ranging from
$6.81 per MMBtu to $8.63 per MMBtu covering a portion of the Company’s 2008,
2009 and 2010 natural gas production. The following financial fixed price swap
transactions were outstanding with associated notional volumes and average
underlying prices that represent hedged prices of commodities at various market
locations at September 30, 2008:
Settlement
Period
|
Derivative
Instrument
|
Hedge
Strategy
|
|
Notional
Daily Volume MMBtu
|
|
|
Total
of Notional Volume MMBtu
|
|
|
Average
Underlying Prices MMBtu
|
|
|
Total
of Proved Natural Gas Production Hedged (1)
|
|
|
Fair
Market Value Gain/(Loss) (In thousands)
|
|
2008
|
Swap
|
Cash
flow
|
|
|
67,892 |
|
|
|
6,246,092 |
|
|
|
7.75 |
|
|
|
52 |
% |
|
$ |
5,246 |
|
2009
|
Swap
|
Cash
flow
|
|
|
52,141 |
|
|
|
19,031,465 |
|
|
|
7.65 |
|
|
|
44 |
% |
|
|
(4,942 |
) |
2010
|
Swap
|
Cash
flow
|
|
|
10,000 |
|
|
|
3,650,000 |
|
|
|
8.31 |
|
|
|
9 |
% |
|
|
(374 |
) |
|
|
|
|
|
|
|
|
|
28,927,557 |
|
|
|
|
|
|
|
|
|
|
$ |
(70 |
) |
(1)
Estimated based on net gas reserves presented in the December 31, 2007
Netherland, Sewell, & Associates, Inc. reserve report.
The
Company has also entered into costless collar transactions covering a portion of
the Company’s 2008 and 2009 natural gas production. The costless collars have an
average floor price of $8.00 per MMBtu and an average ceiling price of $10.15
per MMBtu. 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 September 30,
2008:
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/(Loss) (In thousands)
|
|
2008
|
Costless
Collar
|
Cash
flow
|
|
|
5,000 |
|
|
|
460,000 |
|
|
$ |
8.00 |
|
|
$ |
10.55 |
|
|
|
4 |
% |
|
$ |
501 |
|
2009
|
Costless
Collar
|
Cash
flow
|
|
|
5,000 |
|
|
|
1,825,000 |
|
|
$ |
8.00 |
|
|
$ |
10.05 |
|
|
|
4 |
% |
|
|
821 |
|
|
|
|
|
|
|
|
|
|
2,285,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,322 |
|
1)
Estimated based on net gas reserves presented in the December 31, 2007
Netherland, Sewell, & Associates, Inc. reserve report.
In
addition, the Company has hedged the interest rates on $75.0 million of its
outstanding debt through 2008 and $50.0 million through June
2009. As of September 30, 2008, the Company had the following
financial interest rate swap positions outstanding:
Settlement
Period
|
Derivative
Instrument
|
Hedge
Strategy
|
|
Average
Fixed Rate
|
|
|
Fair
Market Value Gain/(Loss) (In thousands)
|
|
2008
|
Swap
|
Cash
Flow
|
|
|
4.41 |
% |
|
$ |
(156 |
) |
2009
|
Swap
|
Cash
Flow
|
|
|
4.55 |
% |
|
|
(362 |
) |
|
|
|
|
|
|
|
|
$ |
(518 |
) |
The
Company presents the fair value of its derivatives for which a master netting
agreement exists on a net basis in accordance with FASB Interpretation No. 39,
“Offsetting of Amounts Related to Certain Contracts an interpretation of APB
Opinion No. 10 and FASB Statement No. 105” (“FIN 39”).
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 for any margin obligation due to a negative
change in fair market value of the derivative contracts in connection with the
Company’s hedge related credit obligations. As of September 30, 2008,
the Company made no deposits for collateral.
The
following table sets forth the results of the Company’s hedge transactions for
the periods indicated below.
|
|
Three
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
Natural
Gas
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Quantity
settled (MMBtu)
|
|
|
6,706,092 |
|
|
|
6,009,100 |
|
|
|
19,498,524 |
|
|
|
17,750,400 |
|
Increase
(Decrease) in natural gas sales revenue (In thousands)
|
|
$ |
(12,125 |
) |
|
$ |
10,333 |
|
|
$ |
(29,420 |
) |
|
$ |
17,810 |
|
The
following table sets forth the results of the Company’s interest rate hedging
transactions for the periods indicated below.
|
|
Three
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
Interest
Rate Swaps
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Decrease
in interest expense (In thousands)
|
|
|
(372 |
) |
|
$ |
- |
|
|
|
(832 |
) |
|
$ |
- |
|
As of
September 30, 2008, the Company expects to reclassify gains of $4.1 million to
earnings from the balance in accumulated other comprehensive income (loss) on
the Consolidated Balance Sheet during the next twelve months.
(5)
|
Fair
Value Measurements
|
As
discussed in Note 1, the Company partially adopted SFAS No. 157 effective
January 1, 2008. As defined in SFAS No. 157, fair value is the amount
that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date (“exit
price”). To estimate fair value, the Company utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable,
market corroborated or generally unobservable. SFAS No. 157
establishes a fair value hierarchy that prioritizes the inputs to valuation
techniques used to measure fair value. The hierarchy gives the
highest priority to unadjusted quoted market prices in active markets for
identical assets or liabilities (“Level 1”) and the lowest priority to
unobservable inputs (“Level 3”). The three levels of the fair value
hierarchy are as follows:
|
·
|
Level
1 inputs are quoted prices (unadjusted) in active markets for identical
assets or liabilities.
|
|
·
|
Level
2 inputs are quoted prices for similar assets and liabilities in active
markets or inputs that are observable for the asset or liability, either
directly or indirectly through market corroboration, for substantially the
full term of the financial
instrument.
|
|
·
|
Level
3 inputs are measured based on prices or valuation models that require
inputs that are both significant to the fair value measurement and less
observable from objective
sources.
|
Level 3
instruments include natural gas swaps, natural gas zero cost collars and
interest rate swaps. The Company utilizes counterparty and third party broker
quotes to determine the valuation of its derivative
instruments. Fair values derived from counterparties and brokers are
further verified using the closing price as of September 30, 2008 for the
relevant NYMEX futures contracts and Intercontinental Exchange traded
contracts for each derivative settlement location. Accordingly, the
Company did not have sufficient corroborating market evidence to support
classifying these assets and liabilities as Level 2.
The
following table sets forth by level within the fair value hierarchy the
Company’s financial assets and liabilities that were accounted for at fair value
on a recurring basis as of September 30, 2008. As required by SFAS No. 157,
financial assets and liabilities are classified in their entirety based on the
lowest level of input that is significant to the fair value measurement. The
Company’s assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of fair value assets
and liabilities and their placement within the fair value hierarchy
levels.
|
|
At
fair value as of September 30, 2008
(In
thousands)
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Total
|
|
Assets
(Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivative contracts
|
|
|
- |
|
|
|
- |
|
|
|
1,252 |
|
|
|
1,252 |
|
Interest
rate swap contracts
|
|
|
- |
|
|
|
- |
|
|
|
(518 |
) |
|
|
(518 |
) |
Total
|
|
|
- |
|
|
|
- |
|
|
|
734 |
|
|
|
734 |
|
The
determination of the fair values above incorporates various factors required
under SFAS No. 157. These factors include the credit standing of the
counterparties involved, the impact of credit enhancements and the impact of the
Company’s nonperformance risk on its liabilities. The
Company considered credit adjustments for the counterparties using current
credit default swap values and default probabilities for each counterparty in
determining fair value.
The table
below presents a reconciliation for the assets and liabilities classified as
Level 3 in the fair value hierarchy during 2008. Level 3 instruments
presented in the table consist of net derivatives that, in management’s
judgment, reflect the assumptions a marketplace participant would have used at
September 30, 2008.
|
|
Derivatives Asset
(Liability)
(In
thousands)
|
|
Balance
as of January 1, 2008
|
|
$ |
(10,792 |
) |
Total
(gains) losses (realized or unrealized)
|
|
|
|
|
included
in earnings
|
|
|
- |
|
included
in other comprehensive income
|
|
|
(18,725 |
) |
Purchases,
issuances and settlements
|
|
|
30,251 |
|
Transfers
in and out of level 3
|
|
|
- |
|
Balance
as of September 30, 2008
|
|
$ |
734 |
|
|
|
|
|
|
Change
in unrealized gains (losses) relating to derivatives still held as of
September 30, 2008
|
|
$ |
- |
|
(6)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (“ARO”) is as
follows:
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
(In
thousands)
|
|
ARO
as of December 31, 2007
|
|
$ |
22,670 |
|
Revision
of previous estimates
|
|
|
1,519 |
|
Liabilities
incurred during period
|
|
|
1,428 |
|
Accretion
expense
|
|
|
1,501 |
|
ARO
as of September 30, 2008
|
|
$ |
27,118 |
|
Of the
total ARO, approximately $1.3 million is classified as a current liability
included in accrued liabilities on the Consolidated Balance Sheet at September
30, 2008.
The
Company’s credit facilities consist of a senior secured revolving line of credit
(“Revolver”) up to $400.0 million with a borrowing base of $400.0 million, which
was increased from $350.0 million in June 2008, and a five-year $75.0 million
second lien term loan.
As of
September 30, 2008, the Company had total outstanding borrowings and letters of
credit of $245.0 million and $1.0 million, respectively. At September
30, 2008, the Company’s weighted average borrowing rate was 4.69
%. Net borrowing availability under the Revolver was $229.0 million
at September 30, 2008. The Company was in
compliance with all covenants at September 30, 2008.
All
amounts drawn under the Revolver are due and payable on April 5,
2010. The principal balance associated with the second lien term loan
is due and payable on July 7, 2010.
The
effective tax rate for the three and nine months ended September 30, 2008 was
37.2% and 38.6%, respectively. The effective tax rate for the three and
nine months ended September 30, 2007 was 37.8% and 37.9%,
respectively. The provision for income taxes differs from the tax
computed at the federal statutory income tax rate primarily due to state income
taxes, tax credits and other permanent differences.
As of September 30, 2008,
the Company had no unrealized tax benefits. There
were no significant changes to the calculation since December 31, 2007. The
Company does not anticipate that total unrecognized tax benefits will
significantly change due to the settlements of audits and the expiration of
statue of limitations prior to September 30, 2009.
(9)
|
Commitments
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 financial position, results of operations or
cash flows.
Calpine
Settlement
On
December 20, 2005, 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”). Two years later, on December 19, 2007, the Bankruptcy Court
confirmed a plan of reorganization for Calpine, which emerged from bankruptcy on
January 31, 2008. During that period, on June 29, 2007, Calpine
commenced an adversary proceeding against the Company in the Bankruptcy Court
(the “Lawsuit”). Over the next fourteen months, the Company
vigorously disputed Calpine’s contentions in the Lawsuit, including any and all
allegations that it underpaid for Calpine’s oil and gas business.
On October
22, 2008, Calpine and the Company announced that they had entered into a
comprehensive settlement agreement (the “Settlement Agreement”) which, among
other things, will (i) resolve all claims in the Lawsuit, (ii) result in Calpine
conveying clean legal title on all remaining oil and gas assets to Rosetta
(except those properties subject to the preferential rights of third parties who
have indicated a desire to exercise their rights), (iii) settle all pending
claims the Company filed in the Calpine bankruptcy, (iv) modify and extend a gas
purchase agreement by which Calpine purchases the Company’s dedicated production
from the Sacramento Valley, California, and (v) formalize the assumption by
Calpine of the July 7, 2005 purchase and sale agreement (together with all
interrelated agreements, the “PSA Agreement”) by which Calpine’s oil and gas
business was conveyed to the Company thus resulting in the parties honoring
their obligations under the PSA Agreement on a going-forward
basis. This Settlement Agreement, although executed by both parties,
does not become effective until the Bankruptcy Court enters a final order
authorizing the execution of the Settlement Agreement and the performance of the
obligations set forth therein. The
settlement consists of $12.4 million payable in cash to Calpine to resolve all
outstanding legal disputes regarding various matters, including Calpine’s
fraudulent conveyance lawsuit. In addition, the Company will pay $84.6 million
to close the original acquisition transaction of the producing properties that
were the subject of the lawsuit. This $84.6 million consists of $67.6 million
which the Company withheld from the purchase price related to properties that
were not conveyed to the Company, as well as $17.0 million for post-closing
adjustments.
Unless
the Bankruptcy Court declines to authorize Calpine to enter into the executed
Settlement Agreement or a party objects to and appeals any order entered by the
Bankruptcy Court approving the Settlement Agreement, the Company anticipates the
Settlement Agreement and the execution of the obligations required thereunder
will be completed by the parties on or before December 1, 2008, and if so, the
Company will record the financial charges during the fourth quarter 2008.
If the settlement closing does not occur by December 31, 2008, or any extended
date as may be mutually agreed among the parties, if applicable, the Settlement
Agreement expires.
Arbitration
between Calpine Corp./the Company and Pogo Producing
Company
On
October 27, 2008, the Company, Calpine and XTO Energy, Inc. (“XTO”), as the
successor to Pogo Producing Company (“Pogo”), agreed to a Title Indemnity
Agreement in which Calpine agreed to indemnify XTO for certain title disputes,
and the Company, Calpine and XTO agreed to dismissal of the arbitration
proceeding against the Company and release of Pogo’s proofs of claim. The
Company’s proofs of claim are being resolved within the framework of the
Settlement Agreement with Calpine, which is subject to bankruptcy court
approval.
(10)
|
Comprehensive
Income
|
The
Company’s total other comprehensive income (loss) is shown below:
|
|
Three
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Accumulated
other comprehensive (loss) income beginning of period
|
|
|
|
|
$ |
(96,756 |
) |
|
|
|
|
$ |
(8,636 |
) |
|
|
|
|
$ |
(7,225 |
) |
|
|
|
|
$ |
6,315 |
|
Net
(loss) income
|
|
|
(99,375 |
) |
|
|
|
|
|
|
12,713 |
|
|
|
|
|
|
|
(32,571 |
) |
|
|
|
|
|
|
39,795 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in fair value of derivative hedging instruments
|
|
|
142,431 |
|
|
|
|
|
|
|
19,723 |
|
|
|
|
|
|
|
(18,002 |
) |
|
|
|
|
|
|
3,202 |
|
|
|
|
|
Hedge
settlements reclassed to income
|
|
|
12,497 |
|
|
|
|
|
|
|
(10,333 |
) |
|
|
|
|
|
|
30,251 |
|
|
|
|
|
|
|
(17,810 |
) |
|
|
|
|
Tax
provision related to hedges
|
|
|
(57,711 |
) |
|
|
|
|
|
|
(3,539 |
) |
|
|
|
|
|
|
(4,563 |
) |
|
|
|
|
|
|
5,508 |
|
|
|
|
|
Total
other comprehensive income (loss)
|
|
|
97,217 |
|
|
|
97,217 |
|
|
|
5,851 |
|
|
|
5,851 |
|
|
|
7,686 |
|
|
|
7,686 |
|
|
|
(9,100 |
) |
|
|
(9,100 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income (loss)
|
|
|
(2,158 |
) |
|
|
|
|
|
|
18,564 |
|
|
|
|
|
|
|
(24,885 |
) |
|
|
|
|
|
|
30,695 |
|
|
|
|
|
Accumulated
other comprehensive income (loss)
|
|
|
|
|
|
$ |
461 |
|
|
|
|
|
|
$ |
(2,785 |
) |
|
|
|
|
|
$ |
461 |
|
|
|
|
|
|
$ |
(2,785 |
) |
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 outstanding common stock awards and 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
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Basic
weighted average number of shares outstanding
|
|
|
50,813 |
|
|
|
50,409 |
|
|
|
50,636 |
|
|
|
50,363 |
|
Dilution
effect of stock option and awards at the end of the period
|
|
|
- |
|
|
|
161 |
|
|
|
- |
|
|
|
209 |
|
Diluted
weighted average number of shares outstanding
|
|
|
50,813 |
|
|
|
50,570 |
|
|
|
50,636 |
|
|
|
50,572 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Anti-dilutive
stock awards and shares
|
|
|
611 |
|
|
|
415 |
|
|
|
617 |
|
|
|
403 |
|
(12)
|
Geographic
Area Information
|
The
Company has one reportable segment, oil and natural gas exploration and
production, as determined in accordance with SFAS No. 131, “Disclosure
About Segments of an Enterprise and Related Information.”
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
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2008
(1)
|
|
|
2007
(1)
|
|
|
2008
(1)
|
|
|
2007
(1)
|
|
|
|
(In
thousands)
|
|
California
|
|
$ |
38,310 |
|
|
$ |
22,110 |
|
|
$ |
118,898 |
|
|
$ |
77,705 |
|
Rocky
Mountains
|
|
|
6,993 |
|
|
|
2,463 |
|
|
|
23,400 |
|
|
|
6,749 |
|
Mid-Continent
|
|
|
615 |
|
|
|
494 |
|
|
|
1,878 |
|
|
|
1,851 |
|
Lobo
|
|
|
53,263 |
|
|
|
30,792 |
|
|
|
150,183 |
|
|
|
84,059 |
|
Perdido
|
|
|
6,678 |
|
|
|
5,951 |
|
|
|
24,514 |
|
|
|
19,289 |
|
State
Waters
|
|
|
13,555 |
|
|
|
529 |
|
|
|
44,292 |
|
|
|
2,176 |
|
Other
Onshore
|
|
|
11,424 |
|
|
|
5,473 |
|
|
|
35,564 |
|
|
|
14,795 |
|
Gulf
of Mexico
|
|
|
11,323 |
|
|
|
11,573 |
|
|
|
43,527 |
|
|
|
27,954 |
|
|
|
$ |
142,161 |
|
|
$ |
79,385 |
|
|
$ |
442,256 |
|
|
$ |
234,578 |
|
(1) Excludes the effects of hedging
losses of $12.1 million and hedging gains of $10.3 million for the three months
ended September 30, 2008 and 2007, respectively, and hedging losses of $29.4
million and hedging gains of $17.8 million for the nine months ended September
30, 2008 and 2007, respectively.
Oil
and Natural Gas Properties
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
|
(In
thousands)
|
|
California
|
|
$ |
578,132 |
|
|
$ |
540,924 |
|
Rocky
Mountains
|
|
|
131,392 |
|
|
|
76,343 |
|
Mid-Continent
|
|
|
14,620 |
|
|
|
14,698 |
|
Lobo
|
|
|
576,736 |
|
|
|
515,096 |
|
Perdido
|
|
|
89,426 |
|
|
|
76,259 |
|
Texas
State Waters
|
|
|
64,430 |
|
|
|
55,918 |
|
Other
Onshore
|
|
|
141,984 |
|
|
|
130,977 |
|
Gulf
of Mexico
|
|
|
155,849 |
|
|
|
155,867 |
|
Other
|
|
|
7,738 |
|
|
|
6,393 |
|
Total
property and equipment
|
|
$ |
1,760,307 |
|
|
$ |
1,572,475 |
|
On October
22, 2008, Calpine and the Company announced that they had entered into a
comprehensive settlement agreement (the “Settlement Agreement”) which, among
other things, will (i) resolve all claims in the Lawsuit, (ii) result in Calpine
conveying clean legal title on all remaining oil and gas assets to Rosetta
(except those properties subject to the preferential rights of third parties who
have indicated a desire to exercise their rights), (iii) settle all pending
claims the Company filed in the Calpine bankruptcy, (iv) modify and extend a gas
purchase agreement by which Calpine purchases Rosetta’s dedicated production
from the Sacramento Valley, California, and (v) formalize the assumption by
Calpine of the July 7, 2005 purchase and sale agreement (together with all
interrelated agreements, the “PSA Agreement”) by which Calpine’s oil and gas
business was conveyed to the Company thus resulting in the parties honoring
their obligations under the PSA Agreement on a going-forward
basis. This Settlement Agreement, although executed by both parties,
does not become effective until the Bankruptcy Court enters a final order
authorizing the execution of the Settlement Agreement and the performance of the
obligations set forth therein. The
settlement consists of $12.4 million payable in cash to Calpine to resolve all
outstanding legal disputes regarding various matters, including Calpine’s
fraudulent conveyance lawsuit. In addition, the Company will pay $84.6 million
to close the original acquisition transaction of the producing properties that
were the subject of the lawsuit. This $84.6 million consists of $67.6 million
which the Company withheld from the purchase price related to properties that
were not conveyed to the Company, as well as $17.0 million for post-closing
adjustments.
Unless
the Bankruptcy Court declines to authorize Calpine to enter into the executed
Settlement Agreement or a party objects to and appeals any order entered by the
Bankruptcy Court approving the Settlement Agreement, Rosetta anticipates the
Settlement Agreement and the execution of the obligations required thereunder
will be completed by the parties on or before December 1, 2008.
On
October 27, 2008, the Company, Calpine and XTO Energy, Inc. (“XTO”), as the
successor to Pogo Producing Company (“Pogo”), agreed to a Title Indemnity
Agreement in which Calpine agreed to indemnify XTO for certain title disputes,
and the Company, Calpine and XTO agreed to dismissal of the arbitration
proceeding against the Company and release of Pogo’s proofs of claim. The
Company’s proofs of claim are being resolved within the framework of the
settlement agreement with Calpine, which is subject to bankruptcy court
approval.
Item
2. Management’s Discussion and Analysis of Financial Condition
and Results of Operations
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 Part I of our Annual
Report on Form 10-K for the year ended December 31, 2007, 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 natural gas and
oil;
|
·
|
The price of
natural gas and oil;
|
·
|
Conditions
in the energy and economic markets;
|
·
|
Changes
or advances in technology;
|
·
|
The
availability and cost of relevant raw materials, goods and
services;
|
·
|
Future
processing volumes and pipeline
throughput;
|
·
|
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;
|
·
|
Failure
of our joint interest partners to fund any or all of their portion of any
capital program;
|
·
|
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;
|
·
|
Failure
of the bankruptcy court to approve the settlement agreement and if the
court fails to approve the settlement agreement, the amount of resources
expended in connection with Calpine’s bankruptcy and its fraudulent
conveyance action, including significant ongoing costs for lawyers,
consultants, experts and all related expenses, as well as all lost
opportunity costs associated with our internal resources dedicated to
these matters and possible impacts on our
reputation;
|
·
|
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,
legal title, regulatory, natural gas administration, marketing and
operational factors relating to the extraction of oil and natural
gas.
|
Overview
The
following discussion addresses material changes in the results of operations for
the three and nine months ended September 30, 2008 compared to the three and
nine months ended September 30, 2007, and the material changes in financial
condition since December 31, 2007. It is presumed that readers have
read or have access to our 2007 Annual Report on Form 10-K for the year ended
December 31, 2007, which includes, as part of Management’s Discussion and
Analysis of Financial Condition and Results of Operations, disclosures regarding
critical accounting policies.
The
following summarizes our performance for the first nine months of 2008 as
compared to the same period for 2007:
·
|
Production
on an equivalent basis increased
27%;
|
·
|
Total
revenue, including the effects of hedging, increased $160.4 million or
64%;
|
·
|
Impairment
of oil and gas properties of $205.7 million pre-tax ($129.1 million net of
tax) that includes the impact of unfavorable reserve
revisions;
|
·
|
Net
loss of $32.6 million; net income/loss, excluding the impairment charge of
$129.1 million, would have increased $56.8 million or
143%;
|
·
|
Diluted loss
per share of $0.64; diluted earnings/loss per share, excluding the
impairment charge of $129.1 million, would have increased $1.10 or
139%;
|
·
|
Drilled
112 gross wells with a success rate of 86%;
and
|
·
|
In
mid September 2008, we sustained damage to our Sabine Lake and East
Cameron 88/89 production facilities as a result of Hurricane
Ike. Repairs at Sabine Lake have now been completed and
production resumed on October 28, 2008. All critical long-lead
equipment and materials have been secured for the commencement of repairs
at the East Cameron facility and production is anticipated to resume there
before the end of the year.
|
Since
inception in July 2005, Rosetta has delivered top-line production growth by
executing a business model based predominantly upon conventional exploration and
exploitation. The Company actively pursued opportunities in conventional basins
and plays characterized by high decline rates. In early 2008, we began a
strategic shift toward a business model that we believed could generate
more sustainable, predictable performance over time. Accordingly, we have been
on a path to de-emphasize high-decline rate, conventional programs in the Gulf
of Mexico and Texas State Waters, while focusing on building positions and
programs in unconventional onshore domestic basins. These basins are
characterized by having lower risk project inventory and repeatable programs.
Consistent with the nature of unconventional resources, we would expect annual
growth rates to moderate compared to historical top-line growth rates as we
shift to more resource-driven projects and focus on inventory generation. Our
strategy shift will be accompanied by goals to deliver, over time, both
acceptable rates of top-line growth and growth in proved, probable and possible
reserves in excess of historical performance.
We
believe we can successfully implement our strategy shift because of several
factors. Of note, we believe our core existing onshore assets have upside that
has not been fully analyzed through an unconventional resource lens. We
think this approach could yield additional inventory for the Company over time.
In addition, we have an experienced workforce and management team with
background in unconventional resource operations. Finally, we have a balance
sheet and cost structure that we believe allows us to adapt to the
inevitable industry cycles and current economic downturn. These factors do not
ensure our success in executing our strategy shift, but we believe they provide
an advantage when coupled with a prudent investment approach.
Our plan for implementing
the strategy shift that is underway is to pursue both organic and inorganic
opportunities that meet Rosetta’s criteria for funding, particularly inventory
potential and attractive financial returns. In 2008, we began several
studies to test organic concepts in areas where we currently have
assets for the purpose of identifying possible upside and inventory. We
also began studying new domestic basins where we believe Rosetta can compete
successfully. While we have a preference for organic opportunities, we are
also expanding our capability to evaluate and pursue acquisition opportunities
that make sense for Rosetta. We believe this balanced approach is needed for
long-term success; however, it is not our intention or desire to pursue
acquisitions for the sake of growth.
In the
third quarter, our technical teams reviewed the first of several detailed field
studies. Based upon these studies, and in coordination with our independent
reserve engineers, we recently recognized a downward revision of 50 – 60 Bcfe of
proved reserves, or approximately 12 – 14% of previously estimated
reserves. Of the revision, approximately 30 Bcfe is associated with
the low pressure Emigh and Hamilton plays in the Sacramento Basin. The remainder
of the revision is attributable to other existing properties, including the
South Texas Lobo play. These revisions, coupled with relatively low
commodity prices at the end of the third quarter 2008, resulted in a ceiling
test impairment of $129.1 million, net of tax. We expect to continue evaluating
and testing additional unconventional concepts within our existing assets over
the next several quarters.
On
October 22, 2008, we signed a settlement agreement with Calpine Corporation
(“Calpine”) which is subject to bankruptcy court approval and expires if not
closed by December 31, 2008, or any extended date as may be mutually agreed
among the parties, if any. Under the terms of our settlement
agreement, we have agreed with Calpine to effect a lump sum global settlement
consisting of cash and other contractual consideration, subject to bankruptcy
court approval. The settlement consists of $12.4 million payable in cash to
Calpine to resolve all outstanding legal disputes regarding various matters,
including Calpine’s fraudulent conveyance lawsuit. This settlement resolves all
disputes between the parties, whether relating to the oil and gas property
purchase, Rosetta’s proofs of claim in the bankruptcy and its counter claims, or
otherwise and will
be recorded as a charge to income upon approval from the Bankruptcy Court, which
is expected in the fourth quarter of 2008. In addition, we
will pay $84.6 million to close the original 2005 acquisition transaction of the
producing properties that were the subject of the lawsuit. This $84.6 million
consists of $67.6 million which we withheld from the purchase price related to
properties that were not conveyed to Rosetta, as well as $17.0 million for
post-closing adjustments.
With the
Calpine settlement awaiting bankruptcy court approval and known reserve
revisions behind us, we are in a better position to execute our business plan
and affect our desired goals. We believe that we now have greater operating
control and latitude over critical activities, such as rationalizing our
portfolio, attracting new technical talent, pursuing acquisitions that fit our
strategy, and building sustainable capital project inventory. Given our
relatively low leverage and our balance sheet, we believe we are in a favorable
position to execute a sound capital program in 2009. We are currently
developing our capital expenditures budget for 2009 and expect to approve a
budget that can be funded with operating cash flow. At gas prices of
approximately $7 per Mcf or higher, we believe we can not only maintain
production volumes at roughly current levels, but also fund additional
identified organic and/or inorganic inventory growth programs. Within our core
capital program, we will continue to focus on organic growth in onshore
core areas and continue to minimize capital expenditures in offshore
assets. We retain the discretion to adjust and allocate capital spending
plans in response to market conditions, which could impact targets and
performance.
We
recognize that we are operating in one of the most challenging business
environments in recent history and that the credit crisis, declining oil prices,
lower natural gas prices and a weakening global economic outlook are all
adversely impacting the business environment. We are working with our
lenders to effectively stay abreast of market and creditor conditions to ensure
prudent and timely decisions should market conditions deteriorate
further. We believe that we have sufficient liquidity and operational
flexibility to fund and actively manage our capital expenditures program,
including, but not limited to, capping these expenditures in an annual period to
the cash flows available from operating activities. Also of
note, our capital expenditures are primarily in areas where Rosetta acts as
operator and has high working interests. As a result, we do not
believe we have significant exposure to joint interest partners who
may be unable to fund their portion of any capital program, but we are
monitoring partner situations in light of the current economic environment.
To the
extent that capital expenditures or prudent acquisitions require cash flow in
excess of available funds, we intend to draw on our unused capacity under our
existing revolving credit facility. As of September 30, 2008, the undrawn credit
available to us was $229.0 million. We have not received any
indication from our lenders that draws under the credit facility are restricted
below current availability at this time and we are proactively communicating
with them on a routine basis. We increased our borrowing base in the second
quarter to $400.0 million and are currently in the process of affirming that
borrowing base. We do not anticipate any significant change to the borrowing
base as a result of the reaffirmation process, but we will advise the
marketplace if such a change occurs.
Finally,
with respect to the current market environment for liquidity and access to
credit, the Company, through banks participating in its credit facility, has
invested available cash in money market accounts whose investments are
limited to United States Government Securities, securities backed by the United
States Government, or securities of United States Government agencies. The
Company followed this policy prior to the recent changes in credit markets, and
believes this is an appropriate approach for the investment of Company funds in
the current environment.
All
counterparties to our derivative instruments are participants in our credit
facilities, and we have not received any indication that any of these
counterparties are unable to perform their required obligations under the terms
of the derivative contracts, although we are mindful that this could change and
we are staying alert for such changes. Similarly, we have not received any
indication that any of the banks participating in the existing bank facility are
not capable of performing their obligations under the terms of the credit
agreement.
Critical
Accounting Policies and Estimates
In our
Annual Report on Form 10-K for the year ended December 31, 2007, 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 was calculated using hedge adjusted market prices at September 30,
2008, which were based on a Henry Hub price of $7.12 per MMBtu and a West Texas
Intermediate oil price of $96.37 per Bbl (adjusted for basis and quality
differentials). Cash flow hedges of natural gas production in place at September
30, 2008 increased the calculated ceiling value by approximately $23
million (net of tax). Based upon this analysis and as discussed above, a
write-down of $129.1 million (net of tax) was recorded at September 30,
2008. It is possible that another write-down of our oil and gas
properties could occur in the future should natural gas prices continue to
decline and/or we experience downward adjustments to our estimated proved
reserves.
We have
entered into financial fixed price swaps with prices ranging from $6.81 per
MMBtu to $8.63 per MMBtu covering a portion of our 2008, 2009 and 2010
production of approximately 28.9 million MMBtu. We have also entered into
costless collar transactions covering a portion of our 2008 and 2009 production
of approximately 2.3 million MMBtu. The costless collars have an average floor
price of $8.00 per MMBtu and an average ceiling price of $10.15 per
MMBtu. Approximately 93% of total hedged transactions represent
hedged prices of commodities at PG&E Citygate and Houston Ship
Channel. Our current cash flow hedge positions are with
counterparties who are lenders in our 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 our hedge related credit
obligations. As of September 30, 2008, we made no deposits for
collateral. Our 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 September 30,
2008. Non performance risk was evaluated using current credit default swap
values and default probabilities for each counterparty.
We
utilize counterparty and third party broker quotes to determine the
valuation of our derivative instruments and have used this valuation technique
since adoption of SFAS No. 157 on January 1, 2008 and we have made no
changes or adjustments to our technique since then. Fair values
derived from counterparties and brokers are further verified using the closing
price as of September 30,2008 for the relevant NYMEX futures contracts and
Intercontinental Exchange traded contracts for each derivative settlement
location. We mark to market on a quarterly
basis.
Recent
Accounting Developments
For a
discussion of recent accounting developments, see Note 2 to the Consolidated
Financial Statements in Part I. Item 1. Financial Statements of this Form
10-Q.
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 nine months of 2008 was
$412.8 million, including the effects of hedging, which is an increase of $160.4
million, or 64%, from the nine months ended September 30, 2007. Natural gas
sales, excluding the effects of hedging, increased by $184.5 million with $125.6
million attributable to a 47% increase in natural gas prices and $58.9 million
attributable to a 28% increase in production volumes. Oil sales
increased by $23.2 million with $21.5 million associated with a 76% increase in
the price of oil and $1.7 million associated with increased
production. Approximately 88% of revenue was attributable to natural
gas sales on total volumes of 40.8 Bcfe.
The
following table presents information regarding our revenues and production
volumes:
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
%
Change Increase/ (Decrease)
|
|
|
2008
|
|
|
2007
|
|
|
%
Change Increase/ (Decrease)
|
|
|
|
(In
thousands, except percentages and per unit amounts)
|
|
Natural
gas sales
|
|
$ |
114,308 |
|
|
$ |
79,061 |
|
|
|
45 |
% |
|
$ |
362,894 |
|
|
$ |
225,658 |
|
|
|
61 |
% |
Oil
sales
|
|
|
15,728 |
|
|
|
10,657 |
|
|
|
48 |
% |
|
|
49,941 |
|
|
|
26,730 |
|
|
|
87 |
% |
Total
revenues
|
|
$ |
130,036 |
|
|
$ |
89,718 |
|
|
|
45 |
% |
|
$ |
412,835 |
|
|
$ |
252,388 |
|
|
|
64 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
12.1 |
|
|
|
10.7 |
|
|
|
13 |
% |
|
|
38.1 |
|
|
|
29.7 |
|
|
|
28 |
% |
Oil
(MBbls)
|
|
|
130.3 |
|
|
|
141.4 |
|
|
|
(8 |
%) |
|
|
436.2 |
|
|
|
410.7 |
|
|
|
6 |
% |
Total
Equivalents (Bcfe)
|
|
|
12.9 |
|
|
|
11.6 |
|
|
|
11 |
% |
|
|
40.8 |
|
|
|
32.2 |
|
|
|
27 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$ |
9.47 |
|
|
$ |
7.39 |
|
|
|
28 |
% |
|
$ |
9.51 |
|
|
$ |
7.60 |
|
|
|
25 |
% |
Avg.
Gas Price per Mcf, excluding Hedging
|
|
|
10.47 |
|
|
|
6.42 |
|
|
|
63 |
% |
|
|
10.28 |
|
|
|
7.00 |
|
|
|
47 |
% |
Avg.
Oil Price per Bbl
|
|
|
120.66 |
|
|
|
75.37 |
|
|
|
60 |
% |
|
|
114.48 |
|
|
|
65.08 |
|
|
|
76 |
% |
Avg.
Revenue per Mcfe
|
|
|
10.08 |
|
|
|
7.73 |
|
|
|
30 |
% |
|
|
10.12 |
|
|
|
7.84 |
|
|
|
29 |
% |
Natural
Gas. For the three
months ended September 30, 2008, natural gas revenue increased by 45% or $35.2
million, including the realized impact of derivative instruments, from the same
period in 2007 to $114.3 million. This is primarily due to an
increase of 28% in the average gas price, including the effects of hedging,
which increased by $2.08 from $7.39 per Mcf for the three months ended September
30, 2007 to $9.47 per Mcf for the same period in 2008. In addition,
production volumes increased overall by 13%, or 1.4 Bcfe, primarily through
drilling new wells in the Rockies and production from Sabine Lake in Texas State
Waters prior to hurricane impact in late September. The effect of gas hedging
activities on natural gas revenue for the three months ended September 30, 2008
was a loss of $12.1 million or a decrease of $1.00 per Mcf as compared to a gain
of $10.3 million for the three months ended September 30, 2007.
For the
nine months ended September 30, 2008, natural gas revenue increased by 61% or
$137.2 million, including the realized impact of derivative instruments, from
the same period in 2007 to $362.9 million. This increase was due to a
higher average gas price and increased production volumes. The
average gas price, including the effects of hedging, increased by 25%, or $1.91,
from $7.60 per Mcf for the nine months ended September 30, 2007 to $9.51 per Mcf
for the same period in 2008. The 2008 drilling program successfully
increased the number of producing wells, which along with Sabine Lake coming
online late 2007, contributed to production volumes increasing by 8.4 Bcfe, or
28%. The effect of gas hedging activities on natural gas revenue for
the nine months ended September 30, 2008 was a loss of $29.4 million or a
decrease of $0.77 per Mcf as compared to a gain of $17.8 million for the nine
months ended September 30, 2007.
Crude
Oil. For the three
months ended September 30, 2008, oil revenue was $15.7 million, which is a 48%
increase compared to $10.7 million for the same period in 2007. This
increase is primarily attributable to higher average oil prices of $120.66 per
Bbl for the three months ended September 30, 2008 compared to $75.37 per Bbl for
the same period in 2007. Oil volumes decreased overall by 8% in 2008
with reductions in the Offshore and Onshore Other regions based upon our
decision to shift capital investment away from these areas and toward more
gas-prone, repeatable projects. The reduction in these areas was
partially offset by the production increase in Texas State Waters due to Sabine
Lake operations.
For the
nine months ended September 30, 2008, oil revenue increased by 87%, or $23.2
million compared to the same period in 2007. This increase is
primarily attributable to higher average oil prices of $114.48 per Bbl for the
nine months ended September 30, 2008 compared to $65.08 per Bbl for the same
period in 2007. Oil volumes increased overall by 6% for the nine
months ended September 30, 2008 compared to the same period in 2007 due an
increase in production in Sabine Lake offset by decreases in production in the
Offshore region compared to the same period in 2007.
Operating
Expenses
The
following table presents information regarding our operating
expenses:
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
%
Change Increase/ (Decrease)
|
|
|
2008
|
|
|
2007
|
|
|
%
Change Increase/ (Decrease)
|
|
|
|
(In
thousands, except percentages and per unit amounts)
|
|
Lease
operating expense
|
|
$ |
12,857 |
|
|
$ |
11,912 |
|
|
|
8 |
% |
|
$ |
40,445 |
|
|
$ |
33,274 |
|
|
|
22 |
% |
Production
taxes
|
|
|
2,336 |
|
|
|
1,243 |
|
|
|
88 |
% |
|
|
11,528 |
|
|
|
3,428 |
|
|
|
236 |
% |
Depreciation,
depletion and amortization
|
|
|
46,951 |
|
|
|
38,186 |
|
|
|
23 |
% |
|
|
150,103 |
|
|
|
105,079 |
|
|
|
43 |
% |
Impairment
of oil and gas properties
|
|
|
205,659 |
|
|
|
- |
|
|
|
100 |
% |
|
|
205,659 |
|
|
|
- |
|
|
|
100 |
% |
General
and administrative costs
|
|
|
15,419 |
|
|
|
12,032 |
|
|
|
28 |
% |
|
|
41,042 |
|
|
|
29,999 |
|
|
|
37 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$ |
1.00 |
|
|
$ |
1.03 |
|
|
|
(3 |
%) |
|
$ |
0.99 |
|
|
$ |
1.03 |
|
|
|
(4 |
%) |
Avg.
production taxes per Mcfe
|
|
|
0.18 |
|
|
|
0.11 |
|
|
|
64 |
% |
|
|
0.28 |
|
|
|
0.11 |
|
|
|
155 |
% |
Avg.
DD&A per Mcfe
|
|
|
3.64 |
|
|
|
3.29 |
|
|
|
11 |
% |
|
|
3.68 |
|
|
|
3.26 |
|
|
|
13 |
% |
Avg.
G&A per Mcfe
|
|
|
1.19 |
|
|
|
1.04 |
|
|
|
14 |
% |
|
|
1.01 |
|
|
|
0.93 |
|
|
|
9 |
% |
Lease Operating
Expense. Lease operating expense increased $0.9 million for
the three months ended September 30, 2008 as compared to the three months ended
September 30, 2007. The overall increase is due to higher costs in
workover, direct lease operating expense and ad valorem
taxes. Workover expense increased by $0.8 million in 2008 due to a
tropical storm insurance reimbursement offsetting expense for offshore in the
third quarter of 2007. Direct lease operating expense increased by
$0.4 million due to an increase in the number of producing wells in the Rockies
and several non-operated fields in Texas Other. Ad valorem taxes
increased by $0.2 million in 2008 primarily due to higher property appraisals in
California that were not reflected in 2007 until the fourth
quarter. These increases were partially offset by a $0.5 million
decrease in insurance expense based upon lower rates. The average
lease operating expense decreased to $1.00 per Mcfe for the three months ended
September 30, 2008 from $1.03 per Mcfe for the three months ended September 30,
2007.
Lease
operating expense increased $7.2 million for the nine months
ended September 30, 2008 as compared to the nine months ended September 30,
2007. The overall increase is due to a $4.9 million increase in
direct lease operating expense primarily related to new drilled wells being put
on production in the Rockies, Lobo and several Texas Other fields as well as a
full nine months of Sabine Lake operations. Expense workovers are up
$1.7 million in 2008 compared to 2007 due to a hurricane reimbursement being
received for offshore in 2007. Additionally, ad valorem taxes
increased by $0.8 million in 2008.
Production
Taxes. Production taxes increased $1.1 million for the three
months ended September 30, 2008 as compared to the three months ended September
30, 2007 primarily due to a 11% increase in production volumes coupled with
higher prices, as well as increased production in areas that do not qualify for
the State of Texas high cost gas exemptions.
Production
taxes increased $8.1 million for the nine months ended September 30, 2008 as
compared to the nine months ended September 30, 2007 primarily due to a 27%
increase in production volumes coupled with higher prices, as well as increased
production in areas which do not qualify for the State of Texas high cost gas
exemptions.
Depreciation, Depletion, and
Amortization. Depreciation, depletion and amortization
(“DD&A”) expense increased $8.8 million for the three months ended September
30, 2008 as compared to the three months ended September 30,
2007. This increase is due to an 11% increase in total production and
a higher DD&A rate as compared to 2007. The DD&A rate for the
third quarter of 2008 was $3.64 per Mcfe while the DD&A rate for the third
quarter of 2007 was $3.29 per Mcfe.
DD&A
expense increased $45.0 million for the nine months ended September 30, 2008 as
compared to the nine months ended September 30, 2007. This increase
is due to a 27% increase in total production and a higher DD&A rate as
compared to 2007. The DD&A rate for the respective period in 2008
was $3.68 per Mcfe while the DD&A rate for the same period in 2007 was $3.26
per Mcfe.
Impairment of Oil and Gas
Properties. Based upon the quarterly ceiling test computation
using hedge adjusted market prices in effect at September 30, 2008, and in
conjunction with the third quarter 2008 downward revision of a portion of the
Company’s reserves, the net capitalized
costs of oil and natural gas properties exceeded the cost center ceiling at
September 30, 2008 and an impairment expense of $205.7 million, $129.1 million
net of tax, was recorded.
General and Administrative
Costs. General and administrative costs increased by $3.4 million for the
three months ended September 30, 2008 as compared to the three months ended
September 30, 2007. The higher cost is primarily due to the increase of $4.7
million in legal fees the majority of which are associated with the Calpine
litigation and $1.1 million in higher benefit and bonus costs relating to the
increase in the number of employees. These increases were offset by a
$2.5 million decrease in salaries and wages due to severance expense paid to the
former CEO in the third quarter of 2007.
General
and administrative costs increased by $11.0 million for the nine months ended
September 30, 2008 as compared to the nine months ended September 30,
2007. The higher cost is primarily due to the increase of $9.0
million in legal fees the majority of which are associated with the Calpine
litigation and $2.1 million in higher bonus costs relating to the increase in
the number of employees.
Total
Other Expense
For the
three months ended September 30, 2008, total other expense decreased by $1.4
million as compared to the three months ended September 30, 2007 primarily as a
result of a reduction of interest expense of $1.4 million on debt due to lower
LIBOR rates during the period offset by a decrease in capitalized interest of
$0.2 million. Interest income remained relatively flat period over
period.
For the
nine months ended September 30, 2008, total other expense decreased by $1.7
million as compared to the nine months ended September 30, 2007 primarily as a
result of a reduction of interest expense of $2.7 million on debt due to lower
LIBOR rates during the period offset by a decrease in capitalized interest of
$0.6 million. Interest income remained relatively flat period over
period. Interest income increased by $0.3 million due primarily to
increased cash balances over the prior period.
Provision
for Income Taxes
The
effective tax rate for the three and nine months ended September 30, 2008 was
37.2% and 38.6%, respectively. The effective tax rate for the three
and nine months ended September 30, 2007 was 37.8% and 37.9%,
respectively. The provision for income taxes differs from the
tax computed at the federal statutory income tax rate primarily due to state
income taxes, tax credits and other permanent
differences.
Liquidity
and Capital Resources
Our
primary source of liquidity and capital is our operating cash flow. We also
maintain a committed revolving line of credit, which can be accessed as
needed to supplement operating cash flow. Based upon communication
with our lead bank and information obtained from monitoring the status of our
syndicated group, the Company currently knows of no circumstances that would
limit access to our credit facility or require a change in our debt
structure.
We
believe that we have sufficient liquidity and operational flexibility to fund
and actively manage our capital expenditures program to limit expenditures in an
annual period to the cash flows available from operating activities. This policy
has been in place throughout 2008. To the extent that capital expenditures or
acquisitions require cash flow in excess of available funds, we intend to draw
on our unused capacity under the existing revolving credit facility. As of
September 30, 2008, the undrawn credit available to the Company was $229.0
million. We have not received any indication from our lenders that
draws under the credit facility are restricted below current availability at
this time. We increased our borrowing base in the second quarter of 2008 to
$400.0 million, and are currently in the process of affirming that borrowing
base. We do not anticipate any significant change to the borrowing base as a
result of the reaffirmation process, but we will advise the marketplace if such
a change occurs.
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 in which our derivative transactions are in place.
The Company’s current cash flow hedge positions are with counterparties
who are lenders in the Company’s credit facilities. Based upon
communications with these counterparties, the obligations under these
transactions are expected to continue to be met.
Senior Secured Revolving Line of
Credit. In July 2005, BNP Paribas provided us with a senior
secured revolving line of credit concurrent with 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 in conjunction with the syndication. 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. Accordingly, in May 2007, the borrowing base was
adjusted to $350.0 million and in June 2008 was increased to $400.0
million. Amounts outstanding under the Revolver bear interest at
specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.125% to
1.875%. 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 September 30, 2008, our current ratio was 3.1 to 1.0, as
adjusted per current agreements, and our leverage ratio was 0.6 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 obtained a waiver of
any breach of a loan covenant arising out of Calpine’s institution of Calpine’s
fraudulent conveyance action against us and were in compliance with all
covenants at September 30, 2008. All amounts drawn under the Revolver are due
and payable on April 5, 2010. Availability under the Revolver was
$229.0 million at September 30, 2008. At September 30, 2008, our
weighted average borrowing rate was 4.69 %.
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 bore interest at 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 obtained a waiver of any breach of a loan covenant arising out of
Calpine’s institution of Calpine’s fraudulent conveyance action against us and
were in compliance with all covenants at September 30, 2008. The revised
principal balance of the Term Loan is due and payable on July 7,
2010.
Cash
Flows
The
following table presents information regarding the change in our cash
flow:
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Cash
flows provided by operating activities
|
|
$ |
326,301 |
|
|
$ |
183,553 |
|
Cash
flows used in investing activities
|
|
|
(197,172 |
) |
|
|
(242,837 |
) |
Cash
flows provided by financing activities
|
|
|
2,838 |
|
|
|
10,160 |
|
Net
increase (decrease) in cash and cash equivalents
|
|
$ |
131,967 |
|
|
$ |
(49,124 |
) |
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 liquidity and
capital used to finance our capital program.
Cash
flows provided by operating activities increased by $142.7 million for the nine
months ended September 30, 2008 as compared to the same period for
2007. The increase in 2008 primarily resulted from higher oil
and gas production volumes and prices in 2008. Our working capital
increased from a deficit of $62.9 million to a positive $62.7 million and our
cash balance increased $131.9 million over the same period in 2007 due to a
decrease in capital spending of $66.0 million to $184.9 million, an increase in
production of 8.6 Bcfe to 40.8 Bcfe from 32.2 Bcfe at September 30, 2007 and an
increase in the average price per Mcfe of $2.28 to $10.12 per Mcfe from $7.84
per Mcfe at September 30, 2007.
Investing
Activities. The primary driver of cash used in investing
activities is capital spending.
Cash
flows used in investing activities decreased by $45.7 million for the nine
months ended September 30, 2008 as compared to the same period for
2007. During the nine months ended September 30, 2008, we
participated in the drilling of 112 gross wells as compared to the drilling of
149 gross wells in 2007. Our capital spending in the nine months
ended September 30, 2008 was approximately $155.3 million, primarily in our
Lobo, Rockies and California regions and we acquired non-operating properties in
the San Juan Basin for approximately $29.5 million. Our capital
spending during the same period in 2007 was $250.9 million, primarily in the
Rocky Mountain and Lobo regions and an acquisition of properties located in the
Sacramento Basin of approximately $38.7 million.
Financing
Activities. The primary driver of cash provided by financing
activities are equity transactions associated with the exercise of stock options
pursuant to the terms of our 2005 Long-Term Incentive Plan. The
repurchases of stock represented shares 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 nine months ended September 30, 2008 decreased by
$66.0 million to $184.9 million, versus the same period in
2007. During the nine months ended September 30, 2008, we
participated in the drilling of 112 gross wells, spending approximately $155.4
million, with the majority of the wells being in the Lobo, Rockies and
California regions and acquired non-operating properties in the San Juan Basin
for approximately $29.5 million.
As
discussed under Liquidity and Capital Resources, we expect that our positive
operating cash flow, along with the availability under our Revolver, will be
sufficient to fund our budgeted capital expenditures for 2008, which we
currently project to be approximately $290 million.
We intend
to be prudent and disciplined on our cost structure. We are currently
developing our capital expenditures budget for next year and will endeavor to
maintain capital expenditures at a level that can be funded with operating cash
flow. In light of the current economic outlook and commodity prices,
we expect to continue to focus on organic growth in core areas but shift capital
expenditures from offshore assets to domestic onshore unconventional
assets. In the next year, we expect our production growth will be
moderated by a priority on inventory generation.
Calpine
Matters
On
October 22, 2008, Calpine and the Company signed a Settlement Agreement
which is subject to the Bankruptcy Court’s approval. Under the terms
of this Settlement Agreement, the parties have agreed to a global settlement
resolving all disputes, in return for the payment of cash by Rosetta and the
exchange of mutual consideration between the parties. On October 24,
2008, Calpine filed a motion with the Bankruptcy Court requesting approval and
authorization for its entry into the Settlement Agreement and the performance of
its various obligations thereunder. The Settlement Agreement requires us to pay
$12.4 million in cash to Calpine to resolve all outstanding legal disputes
regarding various matters, including Calpine’s fraudulent conveyance lawsuit.
The parties will exchange mutual releases which will resolve all pending
disputes between the parties, whether relating to the oil and gas property
purchase, Rosetta’s proofs of claim in the bankruptcy and its counter claims,
Calpine’s obligation to convey remaining properties to Rosetta, or
otherwise.
Also
under the Settlement Agreement, we will pay the $84.6 million to close the
original acquisition of the producing properties that Calpine had not yet
conveyed to Rosetta and were also the subject of the Lawsuit. This $84.6 million
is comprised of $67.6 million which we withheld from the July 2005 purchase
price related to those properties that were not conveyed to Rosetta, as well as
$17.0 million for post-closing adjustments that Rosetta had been prepared to pay
in order to conclude all remaining conveyances.
In order
to conclude the original transaction, Calpine will assume pursuant to Section
365 of the Bankruptcy Code the PSA Agreement as amended under the Settlement
Agreement, to exclude certain preferential rights properties that were the
subject of a dispute between Calpine and the third-party preferential right
holders. Otherwise, the parties will fully complete our original acquisition of
Calpine’s oil and gas business, including Calpine’s conveyance to us of all of
the remaining oil and gas assets that were owned by Calpine as of May 1, 2005,
including any such properties that were not listed on the schedules to the PSA
Agreement.
In large
part, the properties remaining to be conveyed to us consist of oil and gas
properties which required consents from the lessors of those properties before
being conveyed, but for which Calpine had not yet obtained consents prior to the
July 7, 2005 closing. As a result of the Settlement Agreement (if
approved by the Bankruptcy Court), we will, in connection with these non-consent
properties, retain the $35.2 million of estimated net revenues from these
properties that had earlier been placed in suspense. Upon obtaining legal title
to these properties, Rosetta will also add approximately 13 BCFE of proved
reserves and 4 MMcfe/d of production.
Rosetta
and Calpine have also agreed in the Settlement Agreement to convert Calpine’s
right to extend its gas purchase agreement for the Company’s Sacramento Basin
production for ten years (upon matching any offers of third parties) to a fixed,
ten-year extension of that contract with certain cost adjustments in favor of
Rosetta. The Marketing Agreement by which Calpine Producer Services
markets and sells Rosetta’s production, which was renewed and extended on July
1, 2007, will expire per its terms on or about June 30, 2009. The Marketing
Agreement may be extended by up to 90 days to allow the Company to transition
those services in-house or to another company.
Rosetta
will use a portion of its excess cash from its 2008 operations to fund this
settlement upon closing. Closing is anticipated to occur by December
1, 2008, provided that the Bankruptcy Court approves Calpine’s motion to approve
this settlement at the hearing scheduled for November 13, 2008, and no party
objects to or appeals any order entered by the Bankruptcy Court approving the
Settlement Agreement. If the settlement closing does not occur by December 31,
2008, or any extended date as may be mutually agreed among the parties, if
applicable, the Settlement Agreement expires.
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 Risk” in our annual report filed on Form
10-K for the year ended December 31, 2007 and Note 4 included in Part I. Item 1.
Financial Statements of this Form 10-Q.
For every
$0.10 increase or decrease in natural gas prices, our earnings will be impacted
by approximately $2.1 million, net of income taxes. The effects of
these derivative transactions on our natural gas sales are discussed above under
“Results of Operations – Natural Gas”. In addition, the majority of
our capital expenditures is discretionary and could be curtailed if our cash
flows decline from expected levels.
Our
current cash flow hedge positions are with counterparties who are lenders in our
credit facilities. Based upon communications with these
counterparties, the obligations under these transactions are expected to
continue to be met. Non performance risk was evaluated using current credit
default swap values and default probabilities for each
counterparty. We currently know of no circumstances that would limit
access to our credit facility or require a change in our debt or hedging
structure.
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 September 30,
2008. Based on that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that, as of September 30, 2008, 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
were no changes in our internal control over financial reporting that occurred
during the most recent fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
PART
II. Other Information
Item
1. Legal Proceedings
We 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 consolidated financial statements.
Calpine
Bankruptcy
On
December 20, 2005, 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”). Two years later, on December 19, 2007, the Bankruptcy Court
confirmed a plan of reorganization for Calpine, which emerged from bankruptcy on
January 31, 2008. During that period, on June 29, 2007, Calpine
commenced an adversary proceeding against the Company in the Bankruptcy Court
(the “Lawsuit”). Over the next fourteen months, Rosetta vigorously
disputed Calpine’s contentions in the Lawsuit, including any and all allegations
that it underpaid for Calpine’s oil and gas business.
On October
22, 2008, Calpine and the Company announced that they had entered into a
comprehensive settlement agreement (the “Settlement Agreement”) which, among
other things, will (i) resolve all claims in the Lawsuit, (ii) result in Calpine
conveying clean legal title on all remaining oil and gas assets to Rosetta
(except those properties subject to the preferential rights of third parties who
have indicated a desire to exercise their rights), (iii) settle all pending
claims the Company filed in the Calpine bankruptcy, (iv) modify and extend a gas
purchase agreement by which Calpine purchases Rosetta’s dedicated production
from the Sacramento Valley, California, and (v) formalize the assumption by
Calpine of the July 7, 2005 purchase and sale agreement (together with all
interrelated agreements, the “PSA Agreement”) by which Calpine’s oil and gas
business was conveyed to the Company thus resulting in the parties honoring
their obligations under the PSA Agreement on a going-forward
basis. This Settlement Agreement, although executed by both parties,
does not become effective until the Bankruptcy Court enters a final order
authorizing the execution of the Settlement Agreement and the performance of the
obligations set forth therein. The
settlement consists of $12.4 million payable in cash to Calpine to resolve all
outstanding legal disputes regarding various matters, including Calpine’s
fraudulent conveyance lawsuit. In addition, the Company will pay $84.6 million
to close the original acquisition transaction of the producing properties that
were the subject of the lawsuit. This $84.6 million consists of $67.6 million
which the Company withheld from the purchase price related to properties that
were not conveyed to the Company, as well as $17.0 million for post-closing
adjustments.
Unless
the Bankruptcy Court declines to authorize Calpine to enter into the executed
Settlement Agreement or a party objects to and appeals any order entered by the
Bankruptcy Court approving the Settlement Agreement, Rosetta anticipates the
Settlement Agreement and the execution of the obligations required thereunder
will be completed by the parties on or before December 1, 2008. If the
settlement closing does not occur by December 31, 2008, or any extended date as
may be mutually agreed among the parties, if applicable, the Settlement
Agreement expires.
Arbitration
between Calpine/Rosetta and Pogo Producing Company
On October 27, 2008, the Company,
Calpine and XTO Energy, Inc. (“XTO”), as the successor to Pogo Producing Company
(“Pogo”), agreed to a Title Indemnity Agreement in which Calpine agreed to
indemnify XTO for certain title disputes, and the Company, Calpine and XTO
agreed to dismissal of the arbitration proceeding against the Company and
release of Pogo’s proofs of claim. The Company’s proofs of claim are being
resolved within the framework of the settlement agreement with Calpine, which is
subject to bankruptcy court approval.
Except
for the risk factors set forth below, there have been no material changes in our
risk factors from those disclosed in Item 1A of our Annual Report on Form 10-K
for the year ended December 31, 2007.
Recent
changes in the financial and credit markets may impact economic growth and oil
and gas prices may continue to be adversely affected by general economic
conditions.
Based on
a number of economic indicators, it appears that growth in global economic
activity has slowed substantially. At the present time, the rate at
which the global economy will slow has become increasingly
uncertain. A continued slowing of global economic growth, and, in
particular, in the United States or China, will likely continue to reduce demand
for oil and natural gas. For example, on October 22, 2008, the price
of oil on the New York Mercantile Exchange fell to $66.75 per barrel for
December 2008 delivery, declining to a 16-month low and from a high of $147.27
per barrel in July 2008. A reduction in the demand for, and the
resulting lower prices of, oil and natural gas could adversely affect our
results of operations.
We
are subject to the full cost ceiling limitation and
we may recognize downward revisions which
will result
in a write-down of our estimated net reserves and
to our proved reserves in the future.
Under the
full cost method, we are subject to quarterly calculations of a “ceiling” or
limitation on the amount of our oil and gas properties that can be capitalized
on our balance sheet. If the net capitalized costs of our oil and gas
properties exceed the cost ceiling, we are subject to a ceiling test write-down
of our estimated net reserves to the extent of such excess. If
required, it would reduce earnings and impact stockholders’ equity in the period
of occurrence and result in lower amortization expense in future
periods. For example,
we recognized a ceiling test impairment of $129.1 million, net of tax, in the
third quarter of 2008.
The
discounted present value of our proved reserves is a major component of the
ceiling calculation and represents the component that requires the most
subjective judgments. However, the associated hedge adjusted market
prices of oil and gas reserves that are included in the discounted present value
of the reserves do not require judgment. The ceiling calculation
requires that prices and costs in effect as of the last day of the quarter be
held constant. However, we may not be subject to a write-down if
prices increase subsequent to the end of a quarter in which a write-down might
otherwise be required. The risk that we will be required to write down the
carrying value of oil and natural gas properties increases when natural gas and
crude oil prices are depressed or volatile. Expense recorded in one
period may not be reversed in a subsequent period even though higher natural gas
and crude oil prices may have increased the ceiling applicable in the subsequent
period.
In
addition, write-downs of proved oil and natural gas properties may occur if we
experience substantial downward adjustments to our estimated proved
reserves. For example,
we recognized a downward revision to our proved reserves in the third quarter of
2008. As we are continuing to evaluate and test our asset base,
it is possible that we may recognize additional revisions to our proved reserves
in the future.
The
current deterioration in the credit markets, combined with a decline in
commodity prices, may impact our capital expenditure level and also our
counterparty risk.
While we
seek to fund our capital expenditures primarily from cash flows from operating
activities, we have in the past also drawn on unused capacity under our existing
revolving credit facility for capital expenditures. While we have not
received any indication from our lenders that our ability to draw on our
existing revolving credit facility has been restricted, it is possible that our
borrowing base, which is based on our oil and gas reserves and is subject to
review and adjustment on a semi-annual basis and other interim adjustments, may
be reduced when it is reviewed. A reduction in our ability to borrow
under our existing revolving credit facility, combined with a reduction in cash
flow from operating activities resulting from a decline in commodity prices, may
require us to reduce our capital expenditures, which may in turn adversely
affect our future growth prospects. Furthermore, if we lack the
resources to dedicate sufficient capital expenditures to our existing oil and
gas leases, we may be unable to produce adequate quantities of oil and gas to
retain these leases and they may expire due to a lack of
production. The loss of a sufficient number of leases could have a
material adverse effect on our results of operations.
Additionally,
while we believe that our existing production is adequately hedged with credit
worthy counterparties, continued deterioration in the credit markets may impact
the credit ratings of our current and potential counterparties and affect their
ability to fulfill their existing obligations to us and their willingness to
enter into future transactions with us.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers for the three
months ended September 30, 2008
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
|
|
July
1 - July 31
|
|
|
22,675 |
|
|
$ |
24.98 |
|
|
|
- |
|
|
|
- |
|
August
1 - August 31
|
|
|
2,642 |
|
|
|
23.28 |
|
|
|
- |
|
|
|
- |
|
September
1 - September 30
|
|
|
4,520 |
|
|
|
20.55 |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
29,837 |
|
|
$ |
24.16 |
|
|
|
- |
|
|
|
- |
|
(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.
Item
5. Other Information
|
(a)
|
Rosetta
reported on Form 8-K during the quarter covered by this report all
information required to be reported on such
form.
|
|
(b)
|
There
have been no material changes to the procedures by which securities
holders may recommend nominees to our board of directors since our most
recent disclosure of such procedures contained in our Annual Report on
Form 10-K for the year ended December 31, 2007 and our definitive proxy
statement filed with respect to our 2008 annual
meeting.
|
|
3.1
|
Certificate
of Incorporation (incorporated herein by reference to Exhibit 3.1 to the
Company’s Registration Statement on Form S-1 filed on October 7, 2005
(Registration No.
333-128888)).
|
|
3.2
|
Bylaws
(incorporated herein by reference to Exhibit 3.2 to the Company’s
Registration Statement on Form S-1 filed on October 7, 2005 (Registration
No. 333-128888)).
|
|
4.1
|
Registration
Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the
Company’s Registration Statement on Form S-1 filed on October 7, 2005
(Registration No.
333-128888)).
|
|
31.1
|
Certification
of Periodic Financial Reports by Randy L. Limbacher 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 Randy L. Limbacher and Michael J.
Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
and 18 U.S.C. Section 1350
|
____________________________________
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
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:
November 7, 2008
ROSETTA
RESOURCES INC.
EXHIBIT
INDEX
Exhibit
Number
|
|
Description
|
|
|
Certification
of Periodic Financial Reports by Randy L. Limbacher 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 Randy L. Limbacher and Michael J.
Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
and 18 U.S.C. Section
1350
|