form10-q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
x
|
Quarterly
Report Pursuant To Section 13 or 15(d) of The Securities Exchange Act of
1934
|
For
The Quarterly Period Ended March 31, 2008
OR
o
|
Transition
Report Pursuant To Section 13 or 15(d) of The Securities Exchange Act of
1934
|
Commission
File Number: 000-51801
ROSETTA
RESOURCES INC.
(Exact
name of registrant as specified in its charter)
|
|
Delaware
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43-2083519
|
(State
or other jurisdiction of incorporation or organization)
|
(I.R.S.
Employer Identification No.)
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|
717
Texas, Suite 2800, Houston, TX
|
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
(Do
not check if smaller reporting company)
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Smaller
Reporting Company o
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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, $.001 par value per share,
outstanding as of May 1, 2008 was
51,428,797.
Part
I – Financial Information
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3
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19
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23
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23
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Part
II – Other Information
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24
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28
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28
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29
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29
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29
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30
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31
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32
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Rule
13a-14(a) Certification executed by Randy L. Limbacher
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Rule
13a-14(a) Certification executed by Michael J. Rosinski
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Section
1350 Certification
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Item
1. Financial Statements
Rosetta
Resources Inc.
Consolidated
Balance Sheet
(In
thousands, except share amounts)
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March
31, 2008
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December
31, 2007
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(Unaudited)
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Assets
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Current
assets:
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Cash
and cash equivalents
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$ |
45,893 |
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$ |
3,216 |
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Accounts
receivable
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62,640 |
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55,048 |
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Derivative
instruments
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- |
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3,966 |
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Deferred
income taxes
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20,650 |
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- |
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Prepaid
expenses
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9,696 |
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10,413 |
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Other
current assets
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4,087 |
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4,249 |
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Total
current assets
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142,966 |
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76,892 |
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Oil
and natural gas properties, full cost method, of which $41.7 million at
March 31, 2008 and $40.9 million at December 31, 2007 were excluded from
amortization
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1,612,306 |
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1,566,082 |
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Other
fixed assets
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6,903 |
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6,393 |
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1,619,209 |
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1,572,475 |
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Accumulated
depreciation, depletion, and amortization
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(346,757 |
) |
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(295,749 |
) |
Total
property and equipment, net
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1,272,452 |
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1,276,726 |
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Deferred
loan fees
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1,900 |
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2,195 |
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Other
assets
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1,154 |
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1,401 |
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Total
other assets
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3,054 |
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3,596 |
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Total
assets
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$ |
1,418,472 |
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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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$ |
37,281 |
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$ |
33,949 |
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Accrued
liabilities
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47,552 |
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64,216 |
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Royalties
payable
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24,334 |
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18,486 |
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Derivative
instruments
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55,436 |
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2,032 |
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Prepayment
on gas sales
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25,647 |
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20,392 |
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Deferred
income taxes
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- |
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720 |
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Total
current liabilities
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190,250 |
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139,795 |
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Long-term
liabilities:
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Derivative
instruments
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21,917 |
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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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20,686 |
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18,040 |
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Deferred
income taxes
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79,907 |
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67,916 |
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Total
liabilities
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557,760 |
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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, $0.001 par value; authorized 150,000,000 shares; issued 50,672,022
shares and 50,542,648 shares at March 31, 2008 and December 31, 2007,
respectively
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50 |
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50 |
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Additional
paid-in capital
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764,588 |
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762,827 |
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Treasury
stock, at cost;118,271 and 109,303 shares at March 31, 2008 and December
31, 2007, respectively
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(2,224 |
) |
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(2,045 |
) |
Accumulated
other comprehensive loss
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(48,539 |
) |
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(7,225 |
) |
Retained
earnings
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146,837 |
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119,348 |
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Total
stockholders' equity
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860,712 |
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872,955 |
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Total
liabilities and stockholders' equity
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$ |
1,418,472 |
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$ |
1,357,214 |
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Operations
(In
thousands, except per share amounts)
(Unaudited)
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Three
Months Ended
March
31,
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2008
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2007
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Revenues:
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Natural
gas sales
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$ |
112,445 |
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$ |
69,161 |
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Oil
sales
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15,888 |
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6,635 |
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Total
revenues
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128,333 |
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75,796 |
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Operating
Costs and Expenses:
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Lease
operating expense
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13,414 |
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8,796 |
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Depreciation,
depletion, and amortization
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51,414 |
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30,551 |
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Treating
and transportation
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1,305 |
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763 |
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Marketing
fees
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748 |
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663 |
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Production
taxes
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3,437 |
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985 |
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General
and administrative costs
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12,107 |
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8,069 |
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Total
operating costs and expenses
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82,425 |
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49,827 |
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Operating
income
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45,908 |
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25,969 |
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Other
(income) expense
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Interest
expense, net of interest capitalized
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3,554 |
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4,370 |
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Interest
income
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(239 |
) |
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(972 |
) |
Other
(income) expense, net
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(41 |
) |
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- |
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Total
other expense
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3,274 |
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3,398 |
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Income
before provision for income taxes
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42,634 |
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22,571 |
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Provision
for income taxes
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15,145 |
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8,580 |
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Net
income
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$ |
27,489 |
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$ |
13,991 |
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Earnings
per share:
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Basic
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$ |
0.54 |
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$ |
0.28 |
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Diluted
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$ |
0.54 |
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$ |
0.28 |
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Weighted
average shares outstanding:
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Basic
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50,485 |
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50,325 |
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Diluted
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50,719 |
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50,483 |
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The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Cash Flows
(In
thousands)
(Unaudited)
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Three
Months Ended
March
31,
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2008
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2007
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Cash
flows from operating activities
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Net
income
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$ |
27,489 |
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$ |
13,991 |
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Adjustments
to reconcile net income to net cash from operating
activities
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Depreciation,
depletion and amortization
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51,414 |
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30,551 |
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Deferred
income taxes
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|
15,145 |
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8,580 |
|
Amortization
of deferred loan fees recorded as interest expense
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|
295 |
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|
295 |
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Income
from unconsolidated investments
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- |
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(47 |
) |
Stock
compensation expense
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273 |
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1,352 |
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Change
in operating assets and liabilities:
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Accounts
receivable
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(7,592 |
) |
|
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(366 |
) |
Prepaid
expenses
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|
717 |
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(10,537 |
) |
Other
current assets
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|
162 |
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|
|
(479 |
) |
Other
assets
|
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|
187 |
|
|
|
296 |
|
Accounts
payable
|
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|
3,332 |
|
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|
2,647 |
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Accrued
liabilities
|
|
|
720 |
|
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(2,285 |
) |
Royalties
payable
|
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|
11,103 |
|
|
|
2,523 |
|
Net
cash provided by operating activities
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103,245 |
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|
46,521 |
|
Cash
flows from investing activities
|
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|
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|
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Purchases
of property and equipment
|
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|
(61,879 |
) |
|
|
(58,452 |
) |
Disposals
of property and equipment
|
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2 |
|
|
|
- |
|
Other
|
|
|
- |
|
|
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3 |
|
Net
cash used in investing activities
|
|
|
(61,877 |
) |
|
|
(58,449 |
) |
Cash
flows from financing activities
|
|
|
|
|
|
|
|
|
Proceeds
from stock options exercised
|
|
|
1,488 |
|
|
|
114 |
|
Purchases
of treasury stock
|
|
|
(179 |
) |
|
|
(59 |
) |
Net
cash provided by financing activities
|
|
|
1,309 |
|
|
|
55 |
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease) in cash
|
|
|
42,677 |
|
|
|
(11,873 |
) |
Cash
and cash equivalents, beginning of period
|
|
|
3,216 |
|
|
|
62,780 |
|
Cash
and cash equivalents, end of period
|
|
$ |
45,893 |
|
|
$ |
50,907 |
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash disclosures:
|
|
|
|
|
|
|
|
|
Capital
expenditures included in accrued liabilities
|
|
$ |
19,254 |
|
|
$ |
26,352 |
|
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 such amounts
to corresponding 2008 classifications. 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 March 31, 2008 and December 31, 2007 and for the three months
ended March 31, 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”), which addresses how companies should measure
fair value when companies are required to use a fair value measure for
recognition or disclosure purposes under generally accepted accounting
principles (“GAAP”). As a result of SFAS No. 157, there is now a common
definition of fair value to be used throughout GAAP. SFAS No. 157 is effective
for financial statements issued for fiscal years beginning after November 15,
2007, and interim periods within those years. The FASB has also issued Staff
Position FAS 157-2 (“FSP No. 157-2”), which delays 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 as discussed in Note 5 and has chosen to defer the implementation of
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 which are disclosed or recognized at fair value on a nonrecurring
basis, such as asset retirement obligations, financial instruments reported
under SFAS No. 107 “Disclosures about Fair Value of Financial Instruments”, and
other assets and liabilities in the first quarter of 2009. The
Company does not expect the adoption of FSP No. 157-2 to have a material impact
on the Company’s consolidated financial position, results of operations or cash
flows.
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. We have not
elected 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
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 this
standard.
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.
(3)
|
Property,
Plant and Equipment
|
The
Company’s total property, plant and equipment consists of the
following:
|
|
March 31,
2008
|
|
|
December 31,
2007
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$ |
1,541,186 |
|
|
$ |
1,499,046 |
|
Unproved/unevaluated
properties
|
|
|
41,702 |
|
|
|
40,903 |
|
Gas
gathering systems and compressor stations
|
|
|
29,418 |
|
|
|
26,133 |
|
Other
|
|
|
6,903 |
|
|
|
6,393 |
|
Total
oil and natural gas properties
|
|
|
1,619,209 |
|
|
|
1,572,475 |
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(346,757 |
) |
|
|
(295,749 |
) |
Total
property and equipment, net
|
|
$ |
1,272,452 |
|
|
$ |
1,276,726 |
|
The
Company capitalizes internal costs directly identified with acquisition,
exploration and development activities. The Company capitalized $1.4 million and
$1.3 million of internal costs for the three months ended March 31, 2008 and
2007, respectively.
Included
in the Company’s oil and gas properties are asset retirement costs of $20.3
million and $20.1 million at March 31, 2008 and December 31, 2007,
respectively.
Oil and
gas properties include costs of $41.7 million and $40.9 million at March 31,
2008 and December 31, 2007, respectively, which were excluded from capitalized
costs being amortized. These amounts primarily represent unproved
properties and unevaluated exploration projects in which the Company owns a
direct interest.
The
Company’s ceiling test computation was calculated using hedge adjusted market
prices at March 31, 2008, which were based on a Henry Hub price of $9.37 per
MMBtu and a West Texas Intermediate oil price of $105.63 per Bbl (adjusted for
basis and quality differentials). Cash flow hedges of natural gas production in
place at March 31, 2008 decreased the calculated ceiling value by
approximately $37.7 million (net of tax). There was no write-down required to be
recorded at March 31, 2008. Due to the volatility of commodity
prices, should natural gas prices decline in the future, it is possible that a
write-down could occur.
(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 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 March
31, 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
|
|
|
67,909
|
|
|
|
18,673,400 |
|
|
|
7.75
|
|
|
|
52%
|
|
|
|
(39,174 |
) |
2009
|
Swap
|
Cash
flow
|
|
|
52,141
|
|
|
|
19,031,465 |
|
|
|
7.65
|
|
|
|
44%
|
|
|
|
(32,731 |
) |
2010
|
Swap
|
Cash
flow
|
|
|
10,000
|
|
|
|
3,650,000 |
|
|
|
8.31
|
|
|
|
9%
|
|
|
|
(1,976 |
) |
|
|
|
|
|
|
|
|
|
41,354,865 |
|
|
|
|
|
|
|
|
|
|
$ |
(73,881 |
) |
(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 production. The costless collars have an average
floor price of $8.00 and an average ceiling price of $10.27. The
following costless collar transactions were outstanding with associated notional
volumes and contracted ceiling and floor prices that represent hedge prices at
various market locations at March 31, 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
|
|
|
|
1,375,000 |
|
|
$ |
8.00 |
|
|
$ |
10.55 |
|
|
|
4%
|
|
|
$ |
(753 |
) |
2009
|
Costless
Collar
|
Cash
flow
|
|
|
5,000
|
|
|
|
1,825,000 |
|
|
$ |
8.00 |
|
|
$ |
10.05 |
|
|
|
4%
|
|
|
$ |
(988 |
) |
|
|
|
|
|
|
|
|
|
3,200,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,741 |
) |
(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 March 31, 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 |
% |
|
$ |
(1,170 |
) |
2009
|
Swap
|
Cash
Flow
|
|
|
4.55 |
% |
|
|
(561 |
) |
|
|
|
|
|
|
|
|
$ |
(1,731 |
) |
We
present the fair value of our 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 with respect to any margin obligation
resulting from a negative change in fair market value of the derivative
contracts in connection with the Company’s hedge related credit
obligations. As of March 31, 2008, the Company made no deposits for
collateral.
The
following table sets forth the results of the Company’s hedge transactions for
the respective period for the Consolidated Statement of Operations:
|
|
Three
Months Ended March 31,
|
|
Natural
Gas
|
|
2008
|
|
|
2007
|
|
Quantity
settled (MMBtu)
|
|
|
6,156,216 |
|
|
|
5,499,500 |
|
(Decrease)/increase
in natural gas sales revenue (In thousands)
|
|
$ |
(701 |
) |
|
$ |
5,044 |
|
The
following table sets forth the results of the Company’s interest rate hedging
transactions settled for the Consolidated Statement of Operations:
|
|
Three
Months Ended March 31,
|
|
Interest
Rate Swaps
|
|
2008
|
|
|
2007
|
|
Decrease
in interest expense (In thousands)
|
|
$ |
(125 |
) |
|
$ |
- |
|
The
Company expects to reclassify losses of $34.8 million based on market pricing as
of March 31, 2008 to earnings from the balance in accumulated other
comprehensive income (loss) on the Consolidated Balance Sheet during the next
twelve months.
At March
31, 2008, the Company had derivative liabilities of $77.4 million, of which
$21.9 million was included in long-term liabilities on the Consolidated Balance
Sheet at March 31, 2008. The derivative instrument assets and
liabilities relate to commodity hedges that represent the difference between
hedged prices and market prices on hedged volumes of the commodities as of March
31, 2008.
Gains and
losses related to ineffectiveness were immaterial for the three months ended
March 31, 2008 and 2007.
(5)
|
Fair
Value Measurements
|
Effective
January 1, 2008, the Company partially adopted SFAS No. 157 “Fair Value
Measurements” (“SFAS No. 157”) as it relates to the valuation of financial
assets and liabilities. 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. The
adoption of SFAS 157 for financial assets and liabilities did not
have a significant effect on our consolidated financial position, results of
operations or cash flows.
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”). We
utilize 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 fair value under
SFAS No. 157 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. We utilize third party broker
quotes to determine the valuation of our derivative instruments,
accordingly, we do 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 March 31, 2008. As required by SFAS 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 March 31, 2008
(In
thousands)
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Total
|
|
Assets
(Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivative contracts
|
|
|
- |
|
|
|
- |
|
|
|
(75,621 |
) |
|
|
(75,621 |
) |
Interest
rate swap contracts
|
|
|
- |
|
|
|
- |
|
|
|
(1,732 |
) |
|
|
(1,732 |
) |
Total
|
|
|
- |
|
|
|
- |
|
|
|
(77,353 |
) |
|
|
(77,353 |
) |
The
determination of the fair values above incorporates various factors required
under SFAS 157. These factors include not only the credit standing of the
counterparties involved and the impact of credit enhancements, but also the
impact of the Company’s nonperformance risk on its liabilities.
The table
below presents a reconciliation for the liabilities measured at fair value on a
recurring basis using significant unobservable inputs (Level 3) during the first
quarter of 2008. The fair values of Level 3 derivative instruments are estimated
using valuation models that utilize both market observable and unobservable
parameters. Level 3 instruments presented in the table consist of net
derivatives valued using pricing models incorporating assumptions that, in
management’s judgment, reflect the assumptions a marketplace participant would
have used at March 31, 2008.
|
|
Derivatives
(In
thousands)
|
|
Balance
as of January 1, 2008
|
|
$ |
(10,792 |
) |
Total
gains or losses (realized or unrealized)
|
|
|
|
|
included
in earnings
|
|
|
- |
|
included
in other comprehensive income
|
|
|
(67,387 |
) |
Purchases,
issuances and settlements
|
|
|
826 |
|
Transfers
in and out of level 3
|
|
|
- |
|
Balance
as of March 31, 2008
|
|
$ |
(77,353 |
) |
|
|
|
|
|
Change
in unrealized gains (losses) included in earnings relating to derivatives
still held as of March 31, 2008
|
|
$ |
- |
|
(6)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (“ARO”) is as
follows:
|
|
Three
Months Ended
March
31, 2008
|
|
|
|
(In
thousands)
|
|
ARO
as of December 31, 2007
|
|
$ |
22,670 |
|
Revision
of previous estimates
|
|
|
(393 |
) |
Liabilities
incurred during period
|
|
|
604 |
|
Accretion
expense
|
|
|
397 |
|
ARO
as of March 31, 2008
|
|
$ |
23,278 |
|
Of the
total ARO, approximately $2.6 million is classified as a current liability
included in accrued liabilities on the Consolidated Balance Sheet at March 31,
2008.
The
Company’s credit facilities consist of a four-year senior secured revolving line
of credit (“Revolver”) up to $400.0 million with a borrowing base of $350.0
million and a five-year $75.0 million second lien term loan, which is the same
as of December 31, 2007.
As of
March 31, 2008, the Company had total outstanding borrowings and letters of
credit of $245.0 million and $1.0 million, respectively. Net
borrowing availability under the Revolver was $179.0 million at March 31,
2008. The Company
was in compliance with all covenants at March 31, 2008.
All
amounts drawn under the Revolver are due and payable on July 7,
2009. The principal balance associated with the second lien term loan
is due and payable on July 7, 2010.
As
of March 31, 2008, the Company had no unrecognized tax benefits.
There were no significant changes to the calculation since year end 2007. The Company
does not anticipate that total unrecognized tax benefits will significantly
change due to the settlement of audits and the expiration of statute of
limitations prior to March 31, 2009.
(9)
|
Commitment
and Contingencies
|
The
Company is party to various oil and natural gas litigation matters arising out
of the normal course of business. The ultimate outcome of each of these matters
cannot be absolutely determined, and the liability the Company may ultimately
incur with respect to any one of these matters in the event of a negative
outcome may be in excess of amounts currently accrued for with respect to such
matters. Management does not believe any such matters will have a material
adverse effect on the Company’s financial position, results of operations or
cash flows.
Calpine
Bankruptcy
On
December 20, 2005, Calpine and certain of its subsidiaries filed for
protection under the federal bankruptcy laws in the United States Bankruptcy
Court of the Southern District of New York (the “Bankruptcy
Court”). On December 19, 2007, the Bankruptcy Court approved
Calpine’s plan of reorganization (“Plan of Reorganization”). On
January 31, 2008, Calpine and certain of its subsidiaries emerged from
bankruptcy (the “Plan Effective Date”).
Calpine’s
Lawsuit Against the Company
On June
29, 2007, Calpine commenced an adversary proceeding against the Company in the
Bankruptcy Court (the “Lawsuit”). The complaint alleges that the purchase by the
Company of the domestic oil and natural gas business owned by Calpine (the
“Assets”) in July 2005 for $1.05 billion, prior to Calpine filing for
bankruptcy, was completed when Calpine was insolvent and was for less than a
reasonably equivalent value. Through the Lawsuit, Calpine is seeking (i)
monetary damages for the alleged shortfall in value it received for these Assets
which it estimates to be approximately $400 million, plus interest, or (ii) in
the alternative, return of the Assets from the Company. The Company believes
that the allegations in the Lawsuit are wholly baseless, and the Company
continues to believe that it is unlikely that this challenge by Calpine to the
fairness of the Acquisition will be successful upon the ultimate disposition of
the Lawsuit or, if necessary, in the appellate courts. The Official Committee of
Equity Security Holders and the Official Committee of the Unsecured Creditors
both intervened in the Lawsuit for the stated purpose of monitoring the
proceedings because the committees claimed to have an interest in the Lawsuit,
which the Company disputes because it believes creditors may be paid in full
under Calpine’s Plan of Reorganization without regard to the Lawsuit and equity
holders have no interest in fraudulent conveyance actions. Under
Calpine’s Plan of Reorganization approved by the Bankruptcy Court on December
19, 2007, the Official Committee of Equity Security Holders was dissolved as of
the Plan Effective Date and no longer has any interest in the
Lawsuit. While the Unsecured Creditors Committee also was officially
dissolved as of the Plan Effective Date, there are provisions under the approved
Plan of Reorganization that will allow it to remain involved in lawsuits to
which it is a party, which may include this Lawsuit.
On
September 10, 2007, the Company filed a motion to dismiss the Lawsuit or,
in the alternative, to stay the Lawsuit. The Bankruptcy Court conducted a
hearing upon the Company’s motion on October 24, 2007. Following the hearing,
the Bankruptcy Court denied the Company’s motion on the basis that certain
issues raised by the Company’s motion were premature as the bankruptcy process
had not yet established how much Calpine’s creditors would
receive. On November 5, 2007, the Company filed its answer,
affirmative defenses and counterclaims with respect to the Lawsuit, denying the
allegations set forth in both counts of the Lawsuit, and asserting affirmative
defenses to Calpine’s claims as well as affirmative counterclaims against
Calpine related to the Acquisition for (i) breach of its covenant of solvency
contained in the Purchase and Sale Agreement with respect to the Acquisition and
interrelated agreements concurrently executed therewith, dated July 7, 2005, by
and among Calpine, the Company, and various other signatories thereto
(collectively, the “Purchase Agreement”), (ii) fraud and fraud in a real estate
transaction, (iii) breach of contract, (iv) conversion, (v) civil theft and (vi)
setoff. Due to the time it has taken the parties to complete document
discovery, the parties have agreed, at this point, to extend the time period for
discovery in the Lawsuit. The Bankruptcy Court has not set a firm discovery
deadline or a trial date.
Remaining
Issues with Respect to the Acquisition
Separate
from the Calpine lawsuit, Calpine has taken the position that the Purchase
Agreement (and its constituent parts) are “executory contracts”, which Calpine
may assume or reject. Following the July 7, 2005 closing of the
Acquisition and as of the date of Calpine’s bankruptcy filing, there were open
issues regarding legal title to certain properties included in the Purchase
Agreement. On September 25, 2007, the Bankruptcy Court approved Calpine’s
Disclosure Statement accompanying its proposed Plan of Reorganization under
Chapter 11 of the Bankruptcy Code, in which Calpine revealed it had not yet
made a decision as to whether to assume or reject its remaining duties and
obligations under the Purchase Agreement. The Company may contend
that the Purchase Agreement is not an executory contract which Calpine may
choose to reject. If the Court were to determine that the Purchase
Agreement is an executory contract, the Company may contend the various
agreements entered into as part of the transaction constitute a single contract
for purposes of assumption or rejection under the Bankruptcy Code, and the
Company may argue that Calpine cannot choose to assume certain of the agreements
and to reject others. This issue may be contested by
Calpine. If the Purchase Agreement is held to be executory, the
deadline by when Calpine must exercise its decision to assume or reject the
Purchase Agreement and the further duties and obligations required therein would
normally have been the date on which Calpine’s Plan of Reorganization was
confirmed; however, in order to address certain issues, Calpine and the Company
have agreed to extend this deadline until fifteen days following the entry of a
final, unappealable order in the Lawsuit, and the parties set forth this
agreement in the Plan of Reorganization approved by the Bankruptcy Court on
December 19, 2007.
Open
Issues Regarding Legal Title to Certain Properties
Under the
Purchase Agreement, Calpine is required to resolve the open issues regarding
legal title to interests in certain properties. At the closing of the
Acquisition on July 7, 2005, the Company retained approximately $75 million
of the purchase price in respect to leases and wells identified by Calpine as
requiring third-party consents or waivers of preferential rights to purchase
that were not received by the parties before closing (“Non-Consent
Properties”). The interests in Non-Consent Properties were not
included in the conveyances delivered at the closing of the
Acquisition. Subsequent analysis determined that a significant
portion of the Non-Consent Properties did not require consents or
waivers. For that portion of the Non-Consent Properties for which
third-party consents were in fact required and for which either the Company or
Calpine obtained the required consents or waivers, as well as for all
Non-Consent Properties that did not require consents or waivers, the Company
contends Calpine was and is obligated to have transferred to the Company the
record title, free of any mortgages and other liens.
The
approximate allocated value under the Purchase Agreement for the portion of the
Non-Consent Properties subject to a third-party’s preferential right to purchase
is $7.4 million. The Company has retained $7.1 million of the
purchase price under the Purchase Agreement for the Non-Consent Properties
subject to the third-party preferential right, and, in addition, a post-closing
adjustment is required to credit the Company for approximately $0.3 million for
a property which was transferred to it but, if necessary, will be transferred to
the appropriate third party under its exercised preferential purchase right upon
Calpine’s performance of its obligations under the Purchase
Agreement.
The
Company believes all conditions precedent for its receipt of record title, free
of any mortgages or other liens, for substantially all of the Non-Consent
Properties (excluding that portion of these properties subject to the
third-party preferential right) were satisfied earlier, and certainly no later,
than December 15, 2005, when the Company tendered the amounts necessary to
conclude the settlement of the Non-Consent Properties.
The
Company believes it is the equitable owner of each of the Non-Consent Properties
for which Calpine was and is obligated to have transferred the record title and
that such properties are not part of Calpine’s bankruptcy
estate. Upon the Company’s receipt from Calpine of record title, free
of any mortgages or other liens, to these Non-Consent Properties (excluding that
portion of these properties subject to a validly exercised third party’s
preferential right to purchase) and further assurances required to eliminate any
open issues on title to the remaining properties discussed below, the
Company had been prepared to conclude the remaining aspects of the
Acquisition. The Company has excluded from its statement of
operations for the three months ended March 31, 2008 and 2007, estimated net
revenues and estimated production from interests in certain leases and wells
being a portion of the Non-Consent Properties, including those properties
subject to preferential rights.
On
September 11, 2007, the Bankruptcy Court entered an order approving that certain
Partial Transfer and Release Agreement (“PTRA”) negotiated by and between the
Company and Calpine which, among other things, resolves issues in regard to
title of certain of the other oil and natural gas properties the Company
purchased from Calpine in the Acquisition and for which payment was made to
Calpine on July 7, 2005. The Company entered into a new Marketing and
Services Agreement (“MSA”) with Calpine Producer Services, L.P. (“CPS”) for a
two-year period commencing on July 1, 2007 but which is subject to earlier
termination by the Company on the occurrence of certain events. The additional
documentation received from Calpine under the PTRA eliminates open issues in the
Company’s title and resolves any issues as to the clarity of the Company’s
ownership in certain properties located in the Gulf of Mexico, California, and
Wyoming (collectively, the “PTRA Properties”), including all oil and gas
properties requiring ministerial approvals, such as leases with the U.S.
Minerals Management Service (“MMS”), California State Lands Commission (“CSLC”)
and U.S. Bureau of Land Management (“BLM”). However, the PTRA was executed
without prejudice to Calpine’s fraudulent conveyance action or its right, if
any, to reject the Purchase Agreement, and without prejudice to the Company’s
rights and legal arguments in relation thereto, including the Company’s various
counterclaims. The PTRA did not otherwise address or resolve open
issues with respect to the Non-Consent Properties and certain other
properties.
The
Company recorded the conveyances of those PTRA Properties in California not
requiring governmental agency approval. On October 30, 2007, the CSLC
approved the assignment of the State of California leases and rights of way to
the Company from Calpine and resolved open issues under an audit the State of
California had conducted as to these PTRA Properties. The Company has
received the ministerial approval by the MMS for the assignment of Calpine’s
interests in MMS Federal Offshore leases for South Pelto 17 and South Timalier
252 to the Company.
Notwithstanding
the PTRA, as a result of Calpine’s bankruptcy filing, it remains uncertain as to
whether Calpine will respond cooperatively as to the remaining outstanding
issues under the Purchase Agreement. If Calpine does not fulfill its contractual
obligations (as a result of rejection of the Purchase Agreement or otherwise)
and does not complete the documentation necessary to resolve these remaining
issues whether under the Purchase Agreement or the PTRA, the Company will pursue
all available remedies, including but not limited to a declaratory judgment to
enforce the Company’s rights and actions to quiet title. After pursuing these
matters, if the Company experiences a loss of ownership with respect to these
properties without receiving adequate consideration for any resulting loss to
the Company, an outcome the Company’s management considers to be unlikely upon
ultimate disposition, including appeals, if any, then the Company could
experience losses which could have a material adverse effect on the Company’s
financial condition, statement of operations or cash flows.
Sale
of Natural Gas to Calpine
In
addition, the issues involving legal title to certain properties, the Company
executed, as part of the interrelated agreements that constitute the Purchase
Agreement, certain natural gas sales agreements with Calpine Energy Services,
L.P. (“CES”), which also filed for bankruptcy on December 20,
2005. During the period following Calpine’s filing for bankruptcy,
CES has continued to make the required deposits into the Company’s margin
account and to timely pay for natural gas production it purchases from the
Company’s subsidiaries under these various natural gas sales
agreements. Although Calpine indicated in conjunction with the Plan
of Reorganization that it intended to assume the CES natural gas sales
agreements with the Company separate from the Purchase Agreement, the Company
disagrees that Calpine may assume anything less than the entire Purchase
Agreement and the parties agreed to postpone any dispute on this issue until
resolution of the Lawsuit.
Calpine’s
Marketing of the Company’s Production
As part
of the PTRA, the Company entered into the MSA with CPS, effective July 1, 2007,
which was approved by the Bankruptcy Court on September 11, 2007. Under the MSA,
CPS provides marketing and related services in relation to the sales of the
Company’s natural gas production and charges the Company a fee. This MSA extends
CPS’ obligations to provide such services until June 30, 2009. The MSA is
subject to early termination by the Company upon the occurrence of certain
events.
Events
within Calpine’s Bankruptcy Case
On June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had previously
sold or agreed to sell to the Company in the Acquisition, to the extent those
leases constitute “unexpired leases of non-residential real property” and were
not fully transferred to the Company at the time of Calpine’s filing for
bankruptcy. The oil and gas leases identified in Calpine’s motion
are, in large part, those properties with open issues in regards to their legal
title in certain oil and natural gas leases which Calpine contends it may
possess some legal interest. According to this motion, Calpine filed
its pending bankruptcy proceeding in order to avoid the automatic forfeiture of
any interest it may have in these leases by operation of a bankruptcy code
deadline. Calpine’s motion did not request that the Bankruptcy Court
determine whether these properties belong to the Company or Calpine, but the
Company understands that Calpine’s motion was meant to allow Calpine to preserve
and avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may
possess, if any, in these oil and natural gas leases. The Company
disputes Calpine’s contention that it may have an interest in any significant
portion of these oil and natural gas leases and intends to take the necessary
steps to protect all of the Company’s rights and interest in and to the
leases. Certain of these properties have been subsequently addressed
under the PTRA discussed above.
On July
7, 2006, the Company filed an objection in response to Calpine’s motion,
wherein the Company asserted that oil and natural gas leases constitute
interests in real property that are not subject to “assumption” under the
Bankruptcy Code. In the objection, the Company also requested that (i) the
Bankruptcy Court eliminate from the order certain Federal offshore leases from
the Calpine motion because these properties were fully conveyed to the Company
in July 2005, and the MMS has subsequently recognized the Company as owner and,
as applicable, operator of all of these Federal offshore leases excepting two of
them which expired before the Company received such recognition by the MMS,
and (ii) any order entered by the Bankruptcy Court be without prejudice to, and
fully preserve the Company’s rights, claims and legal arguments regarding the
characterization and ultimate disposition of the remaining described oil and
natural gas properties. In the Company’s objection, the Company also
urged the Bankruptcy Court to require the parties to promptly address and
resolve any remaining issues under the pre-bankruptcy definitive agreements with
Calpine and proposed to the Bankruptcy Court that the parties could seek
mediation to complete the following:
|
·
|
Calpine’s
conveyance of its retained interests in the Non-Consent Properties to the
Company;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which the Company has
already paid Calpine; and
|
|
·
|
Resolution
of the final amounts the Company is to pay
Calpine.
|
At a
hearing held on July 12, 2006, the Bankruptcy Court took the following
steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the CSLC that the Debtors’ Motion to Assume Non-Residential Leases and
Set Cure Amounts (the “Motion”), did not allow adequate time for an
appropriate response, Calpine withdrew from the list of oil and gas leases
that were the subject of the Motion those leases issued by the United
States (and managed by the MMS) (the “MMS Oil and Gas Leases”) and the
State of California (and managed by the CSLC) (the “CSLC Leases”).
Calpine, the Department of Justice and the State of California agreed to
an extension of the existing deadline to November 15, 2006 to assume or
reject the MMS Oil and Gas Leases and CSLC Leases under Section 365 of the
Bankruptcy Code, to the extent the MMS Oil and Gas Leases and CSLC Leases
are leases subject to Section 365. The effect of these actions was to
render the objection of the Company inapplicable at that time;
and
|
|
·
|
The
Bankruptcy Court also encouraged Calpine and the Company to arrive at a
business solution to all remaining issues including approximately $68
million payable to Calpine for conveyance of the Non-Consent Properties
(excluding the properties subject to third party’s preferential
right).
|
On August
1, 2006, the Company filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts, as well as unliquidated damages in amounts that
have not presently been determined. In the event that Calpine elects
to reject the Purchase Agreement or otherwise refuses to perform its remaining
obligations therein, the Company anticipates it will be allowed to amend its
proofs of claim to assert any additional damages it suffers as a result of the
ultimate impact of Calpine’s refusal or failure to perform under the Purchase
Agreement. In the bankruptcy, Calpine may elect to contest or dispute
the amount of damages the Company seeks in its proofs of claim. The
Company will assert all rights to offset any of its damages against any funds it
possess that may be owed to Calpine. Until the allowed amount of the
Company’s claims are finally established and the Bankruptcy Court issues its
rulings with respect to Calpine’s approved Plan of Reorganization, the Company
cannot predict what amounts it may recover from the Calpine bankruptcy should
Calpine reject or refuse to perform under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases and the
CSLC Leases respectively, these parties further extended this deadline by
stipulation. The deadline was first extended to January 31, 2007, was further
extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April
30, 2007 with respect to the CSLC Leases, was further extended again to
September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007
and, October 31, 2007 with respect to the CSLC Leases. The Bankruptcy Court
entered Orders related to the MMS Oil and Gas Leases and CSLC Leases which
included appropriate language that the Company negotiated with Calpine for the
Company’s protection in this regard. The MMS Oil and Gas Leases and CSLC Leases
were included in the PTRA that was approved by the Bankruptcy Court on September
11, 2007, with the result that there is no further need for the parties to
contest whether the MMS Oil and Gas Leases and the CLSC Leases are appropriate
for inclusion in Calpine’s 365 motion. The PTRA approved
by the Bankruptcy Court, among other things, resolves open issues in regard to
the Company’s title to ownership of all of the unexpired MMS Oil and Gas Leases
and the CLSC Leases. However, the PTRA was executed without prejudice
to Calpine’s fraudulent conveyance action or its rights, if any, to reject the
Purchase Agreement and the Company’s rights and legal arguments in relation
thereto.
On June
20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure
Statement with the Bankruptcy Court. Calpine had indicated in its
filings with the Bankruptcy Court that it believed substantial payments in the
form of cash or newly issued stock, or some combination thereof, would be made
to unsecured creditors under its proposed Plan of Reorganization that could
conceivably result in payment of 100% of allowed claims and possibly provide
some payment to its equity holders. The amounts any plan ultimately
distributes to its various claimants of the Calpine estate, including unsecured
creditors, will depend on the amount of allowed claims that remain
following the objection process. The Bankruptcy Court approved Calpine’s Plan of
Reorganization on December 19, 2007, overruling the Company’s objection to the
releases granted by this plan to prior and current directors and officers of
Calpine and certain of its law firms and other professional
advisors.
On August
3, 2007, the Company and Calpine executed the PTRA, resolving certain open
issues without prejudice to Calpine’s avoidance action and, if the Court
concludes the Purchase Agreement is executory, Calpine’s ability to assume or
reject the Purchase Agreement. The principal terms are as follows:
|
·
|
The
Company extended certain marketing services by executing a new MSA with
CPS through and until June 30, 2009, effective as of July 1,
2007. This agreement is subject to earlier termination rights
by the Company upon the occurrence of certain
events;
|
|
·
|
Calpine
delivers to the Company documents that resolve title issues pertaining to
the PTRA Properties, defined as certain previously purchased oil and gas
properties located in the Gulf of Mexico, California and
Wyoming;
|
|
·
|
The
Company assumes all Calpine's rights and obligations for an audit by the
CSLC on part of the PTRA Properties;
and
|
|
·
|
The
Company assumes all rights and obligations for the PTRA Properties,
including all plugging and abandonment
liabilities.
|
On
September 11, 2007, the Bankruptcy Court approved the PTRA. The PTRA did not
resolve the open issues on the Non-Consent Properties and certain other
properties.
Notwithstanding
the PTRA, as a result of Calpine’s bankruptcy, there remains the possibility
that there will be issues between the Company and Calpine that could amount to
material contingencies in relation to the litigation filed by Calpine against
the Company or the Purchase Agreement, including unasserted claims and
assessments with respect to (i) Calpine’s remaining performance under
the Purchase Agreement and the amounts that will be payable in
connection therewith, (ii) whether or not Calpine and its affiliated debtors
will, in fact, perform their remaining obligations in connection with the
Purchase Agreement and PTRA; and (iii) the issues pertaining to the Non-Consent
Properties.
Arbitration
between Calpine Corp./RROLP and Pogo Producing Company
On
September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico
oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course
of that sale, Pogo made three title defect claims on properties sold by Calpine
(valued at approximately $2.7 million in the aggregate, subject to a $0.5
million deductible assuming no reconveyance) claiming that certain leases
subject to the sale had expired because of lack of production. With the
Company’s assistance, Calpine had undertaken without success to resolve this
matter by obtaining ratifications of a majority of the questionable leases.
Calpine filed for bankruptcy protection before Pogo filed arbitration against
it. Even though this is a retained liability of Calpine, Calpine had earlier
declined to accept the Company’s tender of defense and indemnity when Pogo filed
for arbitration against the Company. The Company filed a motion to
stay this arbitration under the automatic stay provision of the Bankruptcy Code
which motion was granted by the Bankruptcy Court on April 24, 2007. The
Company intends to cooperate with Calpine in defending against Pogo’s claim
should it resume; however, it is too early for management to determine whether
this matter will affect the Company, and if so, in what amount. This
is due, but not limited to uncertainty concerning (i) whether or not Pogo’s
proofs of claim will be fully satisfied by Calpine under its approved Plan of
Reorganization; and (ii) whether, and if so, the extent to which, Calpine may
reimburse the Company for its claim for its defense costs and any arbitration
award regarding the Pogo claim. The Company and Calpine have entered
into a joint defense agreement whereby Calpine has taken over the defense of
Pogo’s claims and is indemnifying the Company.
(10)
|
Comprehensive
Income
|
The
Company’s total comprehensive (loss) income is shown below.
|
|
Three
Months Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Accumulated
other comprehensive (loss) income beginning of period
|
|
|
|
|
$ |
(7,225 |
) |
|
|
|
|
$ |
6,315 |
|
Net
income
|
|
$ |
27,489 |
|
|
|
|
|
|
$ |
13,991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in fair value of derivative hedging instruments
|
|
|
(66,665 |
) |
|
|
|
|
|
|
(32,346 |
) |
|
|
|
|
Hedge
settlements reclassed to income
|
|
|
826 |
|
|
|
|
|
|
|
(5,044 |
) |
|
|
|
|
Tax
effect related to hedges
|
|
|
24,525 |
|
|
|
|
|
|
|
14,096 |
|
|
|
|
|
Total
other comprehensive loss
|
|
|
(41,314 |
) |
|
|
(41,314 |
) |
|
|
(23,294 |
) |
|
|
(23,294 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
loss
|
|
|
(13,825 |
) |
|
|
|
|
|
|
(9,303 |
) |
|
|
|
|
Accumulated
other comprehensive loss
|
|
|
|
|
|
$ |
(48,539 |
) |
|
|
|
|
|
$ |
(16,979 |
) |
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
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Basic
weighted average number of shares outstanding
|
|
|
50,485 |
|
|
|
50,325 |
|
Dilution
effect of stock option and awards at the end of the period
|
|
|
234 |
|
|
|
158 |
|
Diluted
weighted average number of shares outstanding
|
|
|
50,719 |
|
|
|
50,483 |
|
|
|
|
|
|
|
|
|
|
Anti-dilutive
stock awards and shares
|
|
|
311 |
|
|
|
435 |
|
(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
March
31,
|
|
|
|
2008
(1)
|
|
|
2007
(1)
|
|
|
|
(In
thousands)
|
|
California
|
|
$ |
36,771 |
|
|
$ |
27,092 |
|
Rocky
Mountains
|
|
|
6,850 |
|
|
|
1,526 |
|
Mid-Continent
|
|
|
552 |
|
|
|
804 |
|
Lobo
|
|
|
36,144 |
|
|
|
24,876 |
|
Perdido
|
|
|
8,089 |
|
|
|
5,768 |
|
Texas
State Waters
|
|
|
15,032 |
|
|
|
809 |
|
Other
Onshore
|
|
|
10,728 |
|
|
|
4,403 |
|
Gulf
of Mexico
|
|
|
14,868 |
|
|
|
5,474 |
|
Total
revenue
|
|
$ |
129,034 |
|
|
$ |
70,752 |
|
|
(1)
|
Excludes
the effects of hedging losses of $0.7 million and hedging gains of $5.0
million for the three months ended March 31, 2008 and 2007,
respectively.
|
Oil
and Natural Gas Properties
|
|
March
31, 2008
|
|
|
December
31, 2007
|
|
|
|
(In
thousands)
|
|
California
|
|
$ |
554,669 |
|
|
$ |
540,924 |
|
Rocky
Mountains
|
|
|
82,250 |
|
|
|
76,343 |
|
Mid-Continent
|
|
|
14,629 |
|
|
|
14,698 |
|
Lobo
|
|
|
533,342 |
|
|
|
515,096 |
|
Perdido
|
|
|
77,772 |
|
|
|
76,259 |
|
Texas
State Waters
|
|
|
58,052 |
|
|
|
55,918 |
|
Other
Onshore
|
|
|
135,050 |
|
|
|
130,977 |
|
Gulf
of Mexico
|
|
|
156,542 |
|
|
|
155,867 |
|
Other
|
|
|
6,903 |
|
|
|
6,393 |
|
Total
property and equipment
|
|
$ |
1,619,209 |
|
|
$ |
1,572,475 |
|
CAUTIONARY NOTE
REGARDING FORWARD-LOOKING STATEMENTS
This
report includes various “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical fact included or incorporated by reference in this
report are forward-looking statements, including without limitation all
statements regarding future plans, business objectives, strategies, expected
future financial position or performance, expected future operational position
or performance, budgets and projected costs, future competitive position, or
goals and/or projections of management for future operations. In some cases, you
can identify a forward-looking statement by terminology such as “may”, “will”,
“could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”,
“believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”,
the negative of such terms or variations thereon, or other comparable
terminology.
The
forward-looking statements contained in this report are largely based on our
expectations for the future, which reflect certain estimates and assumptions
made by our management. These estimates and assumptions reflect our best
judgment based on currently known market conditions, operating trends, and other
factors. Although we believe such estimates and assumptions to be reasonable,
they are inherently uncertain and involve a number of risks and uncertainties
that are beyond our control. As such, management’s assumptions about future
events may prove to be inaccurate. For a more detailed description of the risks
and uncertainties involved, see Item 1A. Risk Factors in our Annual Report on
Form 10-K for the year ended December 31, 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 markets;
|
·
|
Changes
or advances in technology;
|
·
|
Currency
exchange rates and inflation;
|
·
|
The
availability and cost of relevant raw materials, goods and
services;
|
·
|
Future
processing volumes and pipeline
throughput;
|
·
|
The
occurrence of property acquisitions or
divestitures;
|
·
|
Drilling
and exploration risks;
|
·
|
The
availability and cost of processing and
transportation;
|
·
|
Developments
in oil-producing and natural gas-producing
countries;
|
·
|
Competition
in the oil and natural gas
industry;
|
·
|
The
ability and willingness of our current or potential counterparties or
vendors to enter into transactions with us and/or to fulfill their
obligations to us;
|
·
|
Our
ability to access the capital markets on favorable terms or at
all;
|
·
|
Our
ability to obtain credit and/or capital in desired amounts and/or on
favorable terms;
|
·
|
Present
and possible future claims, litigation and enforcement
actions;
|
·
|
Effects
of the application of applicable laws and regulations, including changes
in such regulations or the interpretation
thereof;
|
·
|
Relevant
legislative or regulatory changes, including retroactive royalty or
production tax regimes, changes in environmental regulation, environmental
risks and liability under federal, state and foreign environmental laws
and regulations;
|
·
|
General
economic conditions, either internationally, nationally or in
jurisdictions affecting our
business;
|
·
|
The
amount of resources expended in connection with Calpine’s bankruptcy 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.
|
ITEM 2. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
Overview
The
following discussion addresses material changes in the results of operations for
the three months ended March 31, 2008 compared to the three months ended March
31, 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.
We
continue to execute our strategy to increase value per share. The
following summarizes our performance for the first three months of 2008 as
compared to the same period for 2007:
·
|
Production
on an equivalent basis increased
42%;
|
·
|
Total
revenue, including the effects of hedging, increased $52.5 million or
69%;
|
·
|
Net
income increased $13.5 million or
96%;
|
·
|
Diluted
earnings per share increased $0.26 or 93%;
and
|
·
|
Drilled
36 gross wells with a success rate of
81%.
|
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 computation was calculated using hedge adjusted market prices at
March 31, 2008, which were based on a Henry Hub price of $9.37 per MMBtu and a
West Texas Intermediate oil price of $105.63 per Bbl (adjusted for basis and
quality differentials). Cash flow hedges of natural gas production in place at
March 31, 2008 decreased the calculated ceiling value by approximately
$37.7 million (net of tax). There was no write-down required to be recorded at
March 31, 2008. Due to the volatility of commodity prices, should
natural gas prices decline in the future, it is possible that a write-down could
occur.
Effective
January 1, 2008, the Company partially adopted SFAS No. 157 “Fair Value
Measurements” (“SFAS No. 157”) as it relates to the valuation of financial
assets and liabilities. SFAS No. 157 defines fair value, establishes
a framework for measuring fair value and expands the related disclosure
requirements. Based upon the fair value hierarchy that prioritizes
the inputs to valuation techniques used to measure fair value, the Company’s
natural gas swaps, natural gas zero cost collars and interest rate swaps were
determined to be Level 3 instruments. 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. The valuation of our derivative instruments was derived from
third party broker quotes. 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.
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.
Results
of Operations
Revenues. Our revenues are derived
from the sale of our oil and natural gas production, which includes the effects
of qualifying hedge contracts. Our revenues may vary significantly
from period to period as a result of changes in commodity prices or volumes of
production sold. Total revenue for the first three months of 2008 was
$128.3 million which is an increase of $52.5 million, or 69%, from the three
months ended March 31, 2007. Natural gas sales, excluding the effects of
hedging, increased by $49.0 million with $21.6 million attributable to a 34%
increase in natural gas prices and $27.4 million attributable to a 43% increase
in production volumes. Oil sales increased by $9.3 million with $7.1
million associated with an increase in the price of oil and an increase of $2.1
million associated with increased production. Approximately 88% of
revenue was attributable to natural gas sales on total volumes of 13.8
Bcfe.
The
following table presents information regarding our revenues and production
volumes:
|
|
Three
Months Ended
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
%
Change
Increase/
(Decrease)
|
|
|
|
(In
thousands, except percentages and per unit amounts)
|
|
Total
revenues
|
|
$ |
128,333 |
|
|
$ |
75,796 |
|
|
|
69 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
12.9 |
|
|
|
9.0 |
|
|
|
43 |
% |
Oil
(MBbls)
|
|
|
158.7 |
|
|
|
120.0 |
|
|
|
32 |
% |
Total
Equivalents (Bcfe)
|
|
|
13.8 |
|
|
|
9.7 |
|
|
|
42 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$ |
8.74 |
|
|
$ |
7.68 |
|
|
|
14 |
% |
Avg.
Gas Price per Mcf excluding Hedging
|
|
|
8.80 |
|
|
|
7.12 |
|
|
|
24 |
% |
Avg.
Oil Price per Bbl
|
|
|
100.10 |
|
|
|
55.29 |
|
|
|
81 |
% |
Avg.
Revenue per Mcfe including hedges
|
|
|
9.29 |
|
|
|
7.81 |
|
|
|
19 |
% |
Natural
Gas. For the three
months ended March 31, 2008, natural gas revenue increased by $43.3 million,
including the realized impact of derivative instruments, from the comparable
period in 2007, to $112.4 million. This increase is primarily due to an increase
in the number of wells producing in 2008 as compared to 2007 as well as an
increase in production volumes in California, which includes the acquisition of
properties in the second quarter of 2007, the Rocky Mountains, the Lobo and
Texas State Waters. Also, the average gas price, including the
effects of hedging, increased by $1.06 from $7.68 for the three months ended
2007 to $8.74 for comparable period in 2008. The effect of gas
hedging activities on natural gas revenue for the three months ended March 31,
2008 was a loss of $0.7 million as compared to a gain of $5.0 million for the
three months ended March 31, 2007.
Crude
Oil. For the three
months ended March 31, 2008, oil revenue was $15.9 million as compared to $6.6
million for the comparable period in 2007. This increase is
attributable to the average realized price increase of $44.81 per Bbl from
$55.29 per Bbl for the three months ended March 31, 2007 to $100.10 per Bbl for
the three months ended March 31, 2008. The increase in oil
production volumes was primarily in Texas State Waters and California.
Operating
Expenses
The
following table presents information regarding our operating
expenses:
|
|
Three
Months Ended
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
%
Change
Increase/
(Decrease)
|
|
|
|
(In
thousands, except percentages and per unit amounts)
|
|
Lease
operating expense
|
|
$ |
13,414 |
|
|
$ |
8,796 |
|
|
|
53 |
% |
Production
taxes
|
|
|
3,437 |
|
|
|
985 |
|
|
|
249 |
% |
Depreciation,
depletion and amortization
|
|
|
51,414 |
|
|
|
30,551 |
|
|
|
68 |
% |
General
and administrative costs
|
|
|
12,107 |
|
|
|
8,069 |
|
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$ |
0.97 |
|
|
$ |
0.91 |
|
|
|
7 |
% |
Avg.
production taxes per Mcfe
|
|
|
0.25 |
|
|
|
0.10 |
|
|
|
150 |
% |
Avg.
DD&A per Mcfe
|
|
|
3.72 |
|
|
|
3.15 |
|
|
|
18 |
% |
Avg.
G&A per Mcfe
|
|
|
0.88 |
|
|
|
0.83 |
|
|
|
6 |
% |
Our
operating expenses are primarily related to the following items:
Lease Operating
Expense. Lease operating expense increased $4.6 million for
the three months ended March 31, 2008 as compared to the three months ended
March 31, 2007. The overall increase is due to a $3.1 million
increase in direct lease operating expense and a $1.2 million increase in ad
valorem tax. The increase in direct lease operating expense is due to
the increase in production of 42% which includes the effect of new wells drilled
in 2008 versus 2007. The increase in ad valorem expense is primarily due to the
higher property appraisals in California.
Production
Taxes. Production taxes increased primarily due to the 42%
increase in production volumes and timing differences related to the State of
Texas high cost gas exemptions and reduced tax rates.
Depreciation, Depletion and
Amortization. Depreciation, depletion and amortization
(“DD&A”) expense increased $20.9 million for the three months ended March
31, 2008 as compared to the three months ended March 31, 2007. The
increase is due to a 42% increase in total production and a higher DD&A rate
as compared to 2007. The DD&A rate for the first quarter of 2008
was $3.72 per Mcfe while the rate for the first quarter of 2007 was $3.15 per
Mcfe. The increase in the rate was due to a higher full cost asset
base over a comparable reserve base in the first quarter of 2008 as compared to
the same period in 2007.
General and Administrative
Costs. General and administrative costs increased by $4.0
million for the three months ended March 31, 2008 as compared to the three
months ended March 31, 2007. This increase is primarily due to the
increase of $5.1 million in legal expenses associated with the Calpine
litigation as well as higher payroll expenses associated with the increase in
the number of employees. The above increase is offset with a decrease
of $1.1 million in stock compensation expense associated with the forfeitures of
stock-based compensation awards and a change in our estimated forfeiture
rate.
Total Other
Expense
Other
expense includes interest expense, interest income and other income/expense, net
which was comparable for the three months ended March 31, 2008 to the three
months ended March 31, 2007. The interest income is earned on cash
balances, which were greater during the quarter ended March 31, 2007 versus
March 31, 2008; however, there was a decrease in the interest expense due to a
lower interest rate on our variable rate debt for the first quarter of 2008
versus the comparable period for 2007.
Provision
for Income Taxes
The
effective tax rate for the three months ended March 31, 2008 and 2007 was 35.5%
and 38.0%, 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 revolving line of credit, which can be accessed as needed to
supplement operating cash flow.
Operating Cash
Flow. Our cash flows depend on many factors, including the
price of oil and natural gas and the success of our development and exploration
activities as well as future acquisitions. We actively manage our exposure to
commodity price fluctuations by executing derivative transactions to hedge the
change in prices of our production, thereby mitigating our exposure to price
declines, but these transactions will also limit our earnings potential in
periods of rising natural gas prices. This derivative transaction activity will
allow us the flexibility to continue to execute our capital plan if prices
decline during the period in which our derivative transactions are in place. 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 are discretionary and could be curtailed if
our cash flows decline from expected levels.
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, upon amendment, as a result of the hedges put in place
in July 2005 and the favorable effects of the exercise of the
over-allotment option we granted in our private equity offering in July 2005. In
July 2005, we repaid $60.0 million of the $225.0 million in original borrowings
on the Revolver. In addition, in 2007, we increased our net borrowings against
the Revolver by $5.0 million, bringing the balance to $170.0
million. The borrowing base is subject to review and adjustment on a
semi-annual basis and other interim adjustments, including adjustments based on
our hedging arrangements. In May 2007, the borrowing base was adjusted to $350.0
million. Amounts outstanding under the Revolver bore interest, at
specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.00% to
1.75%. Such margins will fluctuate based on the utilization of the
facility. Borrowings under the Revolver are collateralized by perfected first
priority liens and security interests on substantially all of our assets,
including a mortgage lien on oil and natural gas properties having at least 80%
of the SEC PV-10 pretax reserve value, a guaranty by all of our domestic
subsidiaries, a pledge of 100% of the stock of domestic subsidiaries and a lien
on cash securing the Calpine gas purchase and sale contract. These
collateralized amounts under the mortgages are subject to semi-annual reviews
based on updated reserve information. We are subject to the financial covenants
of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each
fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0,
calculated at the end of each fiscal quarter for the four fiscal quarters then
ended, measured quarterly with the pro forma effect of acquisitions and
divestitures. At March 31, 2008, our current ratio was 2.4 to 1.0, as adjusted
per current agreements, and our leverage ratio was 0.8 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 March
31, 2008. All amounts drawn under the Revolver are due and payable on
July 7, 2009. Availability under the revolving line of
credit was $179.0 million at March 31, 2008.
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 March 31, 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:
|
|
Three
Months Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Cash
flows provided by operating activities
|
|
$ |
103,245 |
|
|
$ |
46,521 |
|
Cash
flows used in investing activities
|
|
|
(61,877 |
) |
|
|
(58,449 |
) |
Cash
flows provided by financing activities
|
|
|
1,309 |
|
|
|
55 |
|
Net
increase (decrease) in cash and cash equivalents
|
|
$ |
42,677 |
|
|
$ |
(11,873 |
) |
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 $56.7 million for the three
months ended March 31, 2008 as compared to the same period for
2007. The increase in 2008 primarily resulted from higher oil and gas
production and prices. In addition, at March 31, 2008, we had a
working capital deficit of $47.3 million. This deficit was
attributable to the change in the derivative instruments associated with higher
gas prices for 2008.
Investing
Activities. The primary driver of cash used in investing
activities is capital spending.
Cash
flows used in investing activities increased by $3.4 million for the three
months ended March 31, 2008 as compared to the same period for
2007. During the three months ended March 31, 2008, we participated
in the drilling of 36 gross wells as compared to the drilling of 45 wells in
2007.
Financing
Activities. The primary driver of cash provided by financing
activities are equity transactions associated with the exercise of stock options
and vesting of restricted stock.
Cash
flows provided by financing activities increased by $1.2 million as compared to
the same period for 2007. The net increase is primarily
related to the stock options exercised in the first quarter of
2008.
Capital
Expenditures
Our
capital expenditures for the three months ended March 31, 2008 decreased by
$16.3 million to $46.5 million, versus the comparable period in
2007. During the three months ended March 31, 2008, we participated
in the drilling of 36 gross wells with the majority of these being in the Lobo
and DJ Basin regions. Our positive Operating Cash Flow, along with
the availability under our revolving credit facility, are projected to be
sufficient to fund our budgeted capital expenditures for 2008, which are
projected to be $290.1 million for 2008.
Calpine
Matters
On June
29, 2007, Calpine filed an adversary proceeding against us seeking $400 million
plus interest as a result of alleged shortfall in value received for the assets
involved in the Acquisition, or in the alternative, a return of the domestic oil
and gas assets sold to us by Calpine. See Part II. Item 1. Legal
Proceedings for further information regarding the Calpine
litigation.
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 footnote 4 included in Part I.
Item 1. Financial Statements of this Form 10-Q. There have been no
material changes in our exposure to market risk since December 31,
2007.
Item 4. Controls and Procedures
Under the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of the
effectiveness of the design and operation of our disclosure controls and
procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934, as amended (“Exchange Act”), as of March 31,
2008. Based on that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that, as of March 31, 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
reasonable 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 and certain of its subsidiaries filed for
protection under the federal bankruptcy laws in the United States Bankruptcy
Court of the Southern District of New York (the “Bankruptcy
Court”). On December 19, 2007, the Bankruptcy Court approved
Calpine’s plan of reorganization (“Plan of Reorganization”). On
January 31, 2008, Calpine and certain of its subsidiaries emerged from
bankruptcy (the “Plan Effective Date”).
Calpine’s
Lawsuit Against Us
On June
29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy
Court (the “Lawsuit”). The complaint alleges that the purchase by us of the
domestic oil and natural gas business owned by Calpine (the “Assets”) in July
2005 for $1.05 billion, prior to Calpine filing for bankruptcy, was completed
when Calpine was insolvent and was for less than a reasonably equivalent value.
Through the Lawsuit, Calpine is seeking (i) monetary damages for the alleged
shortfall in value it received for these Assets which it estimates to be at
least approximately $400 million plus interest, or (ii) in the alternative,
return of the Assets from us. We believe that the allegations in the Lawsuit are
without merit, and we continue to believe that it is unlikely that this
challenge by Calpine to the fairness of the Acquisition will be successful upon
the ultimate disposition of the Lawsuit, or if necessary, in the appellate
courts. The Official Committee of Equity Security Holders and the Official
Committee of the Unsecured Creditors both intervened in the Lawsuit for the
stated purpose of monitoring the proceedings because the committees claimed to
have an interest in the Lawsuit, which we dispute because we believe creditors
may be paid in full under Calpine’s Plan of Reorganization without regard to the
Lawsuit and equity holders have no interest in fraudulent conveyance
actions. Under Calpine’s Plan of Reorganization approved by the
Bankruptcy Court on December 19, 2007, the Official Committee of Equity Security
Holders was dissolved as of the Plan Effective Date and no longer has any
interest in the Lawsuit. While the Unsecured Creditors Committee also
was officially dissolved as of the Plan Effective Date, there are provisions
under the approved Plan of Reorganization that will allow it to remain involved
in lawsuits to which it is a party, which may include this Lawsuit.
On
September 10, 2007, we filed a motion to dismiss the Lawsuit or in the
alternative, to stay the Lawsuit. The Bankruptcy Court conducted a hearing upon
our motion on October 24, 2007. Following the hearing, the
Bankruptcy Court denied our motion on the basis that certain issues we raised in
our motion were premature as the bankruptcy process had not yet established how
much Calpine’s creditors would receive. On November 5, 2007, we filed
our answer, affirmative defenses and counterclaims with respect to the Lawsuit,
denying the allegations set forth in both counts of the Lawsuit, and asserting
affirmative defenses to Calpine’s claims as well as affirmative counterclaims
against Calpine related to the Acquisition for (i) breach of its covenant of
solvency contained in the Purchase and Sale Agreement with respect to the
Acquisition and interrelated agreements concurrently executed therewith, dated
July 7, 2005, by and among Calpine, us, and various other signatories thereto
(collectively, the “Purchase Agreement”), (ii) fraud and fraud in a real estate
transaction, (iii) breach of contract, (iv) conversion, (v) civil theft and (vi)
setoff. Due to the time it has taken the parties to complete document
discovery, the parties have agreed, at this point, to extend the time period for
discovery in the Lawsuit. The Bankruptcy Court has not set a firm discovery
deadline or a trial date.
Remaining
Issues with Respect to the Acquisition
Separate
from the Calpine lawsuit, Calpine has taken the position that the Purchase
Agreement (and its constituent parts) are “executory contracts”, which Calpine
may assume or reject. Following the July 7, 2005 closing of the
Acquisition and as of the date of Calpine’s bankruptcy filing, there were open
issues regarding legal title to certain properties included in the Purchase
Agreement. On September 25, 2007, the Bankruptcy Court approved Calpine’s
Disclosure Statement accompanying its proposed Plan of Reorganization under
Chapter 11 of the Bankruptcy Code, in which Calpine revealed it had not yet
made a decision as to whether to assume or reject its remaining duties and
obligations under the Purchase Agreement. We may contend that the
Purchase Agreement is not an executory contract which Calpine may choose to
reject. If the Court were to determine that the Purchase Agreement is
an executory contract, we may contend the various agreements entered into as
part of the transaction constitute a single contract for purposes of assumption
or rejection under the Bankruptcy Code, and we may argue that Calpine cannot
choose to assume certain of the agreements and to reject others. This
issue may be contested by Calpine. If the Purchase Agreement is held
to be executory, the deadline by when Calpine must exercise its decision to
assume or reject the Purchase Agreement and the further duties and obligations
required therein would normally have been the date on which Calpine’s
Plan of Reorganization was confirmed; however, in order to address certain
issues, we and Calpine have agreed to extend this deadline until fifteen days
following the entry of a final, unappealable order in the Lawsuit, and the
parties set forth this agreement in the Plan of Reorganization approved by the
Bankruptcy Court on December 19, 2007.
Open
Issues Regarding Legal Title to Certain Properties
Under the
Purchase Agreement, Calpine is required to resolve the open issues regarding
legal title to interests in certain properties. At the closing of the
Acquisition on July 7, 2005, we retained approximately $75 million of the
purchase price in respect to leases and wells identified by Calpine as requiring
third-party consents or waivers of preferential rights to purchase that were not
received by the parties before closing (“Non-Consent
Properties”). The interests in the Non-Consent Properties were not
included in the conveyances delivered at the closing of the
Acquisition. Subsequent analysis determined that a significant
portion of the Non-Consent Properties did not require consents or
waivers. For that portion of the Non-Consent Properties for which
third-party consents were in fact required and for which either us or Calpine
obtained the required consents or waivers, as well as for all Non-Consent
Properties that did not require consents or waivers, we contend Calpine was and
is obligated to have transferred to us the record title, free of any mortgages
and other liens.
The
approximate allocated value under the Purchase Agreement for the portion of the
Non-Consent Properties subject to a third-party’s preferential right to purchase
is $7.4 million. We have retained $7.1 million of the purchase price
under the Purchase Agreement for the Non-Consent Properties subject to the
third-party preferential right, and, in addition, a post-closing adjustment is
required to credit us for approximately $0.3 million for a property which was
transferred to us but, if necessary, will be transferred to the appropriate
third party under its exercised preferential purchase right upon Calpine’s
performance of its obligations under the Purchase Agreement.
We
believe all conditions precedent for our receipt of record title, free of any
mortgages or other liens, for substantially all of the Non-Consent Properties
(excluding that portion of these properties subject to the third-party
preferential right) were satisfied earlier, and certainly no later, than
December 15, 2005, when we tendered the amounts necessary to conclude the
settlement of the Non-Consent Properties.
We
believe we are the equitable owner of each of the Non-Consent Properties for
which Calpine was and is obligated to have transferred the record title and that
such properties are not part of Calpine’s bankruptcy estate. Upon our
receipt from Calpine of record title, free of any mortgages or other liens, to
these Non-Consent Properties (excluding that portion of these properties subject
to a validly exercised third party’s preferential right to purchase) and further
assurances required to eliminate any open issues on title to the remaining
properties discussed below, we have been prepared to conclude the remaining
aspects of the Acquisition. We have not included in our
statement of operations for the three months ended March 31, 2008 and 2007,
estimated net revenues and related estimated production from interests in
certain leases and wells being a portion of the Non-Consent
Properties, including those properties subject to preferential
rights.
On
September 11, 2007, the Bankruptcy Court entered an order approving that certain
Partial Transfer and Release Agreement (“PTRA”) negotiated by and between us and
Calpine which, among other things, resolves issues in regard to title of certain
of the other oil and natural gas properties we purchased from Calpine in the
Acquisition and for which payment was made to Calpine on July 7,
2005. We entered into a new Marketing and Services Agreement (“MSA”)
with Calpine Producer Services, L.P. (“CPS”) for a two-year period commencing on
July 1, 2007 but which is subject to earlier termination by us on the occurrence
of certain events. The additional documentation received from Calpine under the
PTRA eliminates any open issues in our title and resolves any issues as to the
clarity of our ownership in certain properties located in the Gulf of Mexico,
California, and Wyoming (collectively, the “PTRA Properties”), including all oil
and gas properties requiring ministerial approvals, such as leases with the U.S.
Minerals Management Service (“MMS”), California State Lands Commission (“CSLC”)
and U.S. Bureau of Land Management (“BLM”). However, the PTRA was executed
without prejudice to Calpine’s fraudulent conveyance action or its right, if
any, to reject the Purchase Agreement, and without prejudice to our rights and
legal arguments in relation thereto, including our various
counterclaims. The PTRA did not otherwise address or resolve open
issues with respect to the Non-Consent Properties and certain other
properties.
We
recorded the conveyances of those PTRA Properties in California not requiring
governmental agency approval. On October 30, 2007, the CSLC approved
the assignment of the State of California leases and rights of way to us from
Calpine and resolved open issues under an audit the State of California had
conducted as to these PTRA Properties. We have received the
ministerial approval by the MMS for the assignment of Calpine’s interests in MMS
Federal Offshore leases for South Pelto 17 and South Timalier 252 to
us.
Notwithstanding
the PTRA, as a result of Calpine’s bankruptcy filing, it remains uncertain as to
whether Calpine will respond cooperatively as to the remaining outstanding
issues under the Purchase Agreement. If Calpine does not fulfill its contractual
obligations (as a result of rejection of the Purchase Agreement or otherwise)
and does not complete the documentation necessary to resolve these remaining
issues whether under the Purchase Agreement or the PTRA, we will pursue all
available remedies, including but not limited to a declaratory judgment to
enforce our rights and actions to quiet title. After pursuing these matters, if
we experience a loss of ownership with respect to these properties without
receiving adequate consideration for any resulting loss to us, an outcome our
management considers to be unlikely upon ultimate disposition, including
appeals, if any, then we could experience losses which could have a material
adverse effect on our business, financial condition, statement of operations or
cash flows.
Sale of Natural
Gas to Calpine
In
addition to the issues involving legal title to certain properties, we executed,
as part of the interrelated agreements that constitute the Purchase Agreement,
certain natural gas sales agreements with Calpine Energy Services, L.P. (“CES”),
which also filed for bankruptcy on December 20, 2005. During the
period following Calpine’s filing for bankruptcy, CES has continued to make the
required deposits into our margin account and to timely pay for natural gas
production it purchases from our subsidiaries under these various natural gas
sales agreements. Although Calpine indicated in conjunction with the
Plan of Reorganization that it intended to assume the CES natural gas sales
agreements with us separate from the Purchase Agreement, we disagree that
Calpine may assume anything less than the entire Purchase Agreement and the
parties agreed to postpone any dispute on this issue until resolution of the
Lawsuit.
Calpine’s
Marketing of the Company’s Production
As part
of the PTRA, we entered into the MSA with CPS, effective July 1, 2007, which was
approved by the Bankruptcy Court on September 11, 2007. Under the MSA, CPS
provides marketing and related services in relation to the sales of our natural
gas production and charges us a fee. This MSA extends CPS’ obligations to
provide such services until June 30, 2009. The MSA is subject to early
termination by us upon the occurrence of certain events.
Events
within Calpine’s Bankruptcy Case
On June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had previously
sold or agreed to sell to us in the Acquisition, to the extent those leases
constitute “unexpired leases of non-residential real property” and were not
fully transferred to us at the time of Calpine’s filing for
bankruptcy. The oil and gas leases identified in Calpine’s motion
are, in large part, those properties with open issues in regards to their legal
title in certain oil and natural gas leases which Calpine contends it may
possess some legal interest. According to this motion, Calpine filed
its pending bankruptcy proceeding in order to avoid the automatic forfeiture of
any interest it may have in these leases by operation of a bankruptcy code
deadline. Calpine’s motion did not request that the Bankruptcy Court
determine whether these properties belong to us or Calpine, but we understand
Calpine’s motion was meant to allow Calpine to preserve and avoid forfeiture
under the Bankruptcy Code of whatever interest Calpine may possess, if any, in
these oil and natural gas leases. We dispute Calpine’s contention
that it may have an interest in any significant portion of these oil and natural
gas leases and intend to take the necessary steps to protect all of the our
rights and interest in and to the leases. Certain of these properties
have been subsequently addressed under the PTRA discussed above.
On July
7, 2006, we filed an objection in response to Calpine’s motion, wherein we
asserted that oil and natural gas leases constitute interests in real property
that are not subject to “assumption” under the Bankruptcy Code. In the
objection, we also requested that (i) the Bankruptcy Court eliminate from the
order certain Federal offshore leases from the Calpine motion because these
properties were fully conveyed to us in July 2005, and the MMS has subsequently
recognized us as owner and, as applicable, operator of all of these Federal
offshore leases excepting two of them which expired before we received such
recognition by MMS, and (ii) any order entered by the Bankruptcy Court be
without prejudice to, and fully preserve our rights, claims and legal arguments
regarding the characterization and ultimate disposition of the remaining
described oil and natural gas properties. In our objection, we also
urged the Bankruptcy Court to require the parties to promptly address and
resolve any remaining issues under the pre-bankruptcy definitive agreements with
Calpine and proposed to the Bankruptcy Court that the parties could seek
mediation to complete the following:
|
·
|
Calpine’s
conveyance of its retained interests in the Non-Consent Properties to
us;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which we have already
paid Calpine; and
|
|
·
|
Resolution
of the final amounts we are to pay
Calpine.
|
At a
hearing held on July 12, 2006, the Bankruptcy Court took the following
steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the CSLC that the Debtors’ Motion to Assume Non-Residential Leases and
Set Cure Amounts (the “Motion”), did not allow adequate time for an
appropriate response, Calpine withdrew from the list of oil and gas leases
that were the subject of the Motion those leases issued by the United
States (and managed by the MMS) (the “MMS Oil and Gas Leases”) and the
State of California (and managed by the CSLC) (the “CSLC Leases”).
Calpine, the Department of Justice and the State of California agreed to
an extension of the existing deadline to November 15, 2006 to assume or
reject the MMS Oil and Gas Leases and CSLC Leases under Section 365 of the
Bankruptcy Code, to the extent the MMS Oil and Gas Leases and CSLC Leases
are leases subject to Section 365. The effect of these actions was to
render our objection inapplicable at that time;
and
|
|
·
|
The
Bankruptcy Court also encouraged Calpine and us to arrive at a business
solution to all remaining issues including approximately $68 million
payable to Calpine for conveyance of the Non-Consent Properties (excluding
the properties subject to third party’s preferential
right).
|
On August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts, as well as unliquidated damages in amounts that
have not presently been determined. In the event that Calpine elects
to reject the Purchase Agreement or otherwise refuses to perform its remaining
obligations therein, we anticipate we will be allowed to amend our proofs of
claim to assert any additional damages we suffer as a result of the ultimate
impact of Calpine’s refusal or failure to perform under the Purchase
Agreement. In the bankruptcy, Calpine may elect to contest or dispute
the amount of damages we seek in our proofs of claim. We will assert
all rights to offset any of our damages against any funds we possess that may be
owed to Calpine. Until the allowed amount of our claims are finally
established and the Bankruptcy Court issues its rulings with respect to
Calpine’s approved Plan of Reorganization, we cannot predict what amounts we may
recover from the Calpine bankruptcy should Calpine reject or refuse to perform
under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases and the
CSLC Leases respectively, these parties further extended this deadline by
stipulation. The deadline was first extended to January 31, 2007, was further
extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April
30, 2007 with respect to the CSLC Leases, was further extended again to
September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007
and, October 31, 2007 with respect to the CSLC Leases. The Bankruptcy Court
entered Orders related to the MMS Oil and Gas Leases and CSLC Leases which
included appropriate language that we negotiated with Calpine for our protection
in this regard. The MMS Oil and Gas Leases and CSLC Leases were
included in the PTRA that was approved by the Bankruptcy Court on September 11,
2007, with the result that there is no further need for the parties to contest
whether the MMS Oil and Gas Leases and the CLSC Leases are appropriate for
inclusion in Calpine’s 365 motion. The PTRA approved by the Bankruptcy Court,
among other things, resolves open issues in regard to our title to ownership of
all of the unexpired MMS Oil and Gas Leases and the CLSC
Leases. However, the PTRA was executed without prejudice to Calpine’s
fraudulent conveyance action or its rights, if any, to reject the Purchase
Agreement and our rights and legal arguments in relation thereto.
On June
20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure
Statement with the Bankruptcy Court. Calpine had indicated in its
filings with the Bankruptcy Court that it believed substantial payments in the
form of cash or newly issued stock, or some combination thereof, would be made
to unsecured creditors under its proposed Plan of Reorganization that could
conceivably result in payment of 100% of allowed claims and possibly provide
some payment to its equity holders. The amounts any plan ultimately
distributes to its various claimants of the Calpine estate, including unsecured
creditors, will depend on the amount of allowed claims that remain following the
objection process. The Bankruptcy Court approved Calpine’s Plan of
Reorganization on December 19, 2007, overruling our objection to the releases
granted by this plan to prior and current directors and officers of Calpine and
certain of its law firms and other professional advisors.
On August
3, 2007, we executed the PTRA, resolving certain open issues without prejudice
to Calpine’s avoidance action and, if the Court concludes the Purchase Agreement
is executory, Calpine’s ability to assume or reject the Purchase
Agreement. The principal terms are as follows:
|
·
|
We
extended certain marketing services by executing a new MSA with CPS
through and until June 30, 2009, effective as of July 1,
2007. This agreement is subject to earlier termination rights
by us upon the occurrence of certain
events;
|
|
·
|
Calpine
delivers to us documents that resolve title issues pertaining to the PTRA
Properties defined as certain previously purchased oil and gas properties
located in the Gulf of Mexico, California and
Wyoming;
|
|
·
|
We
assume all Calpine's rights and obligations for an audit by the CSLC on
part of the PTRA Properties; and
|
|
·
|
We
assume all rights and obligations for the PTRA Properties, including all
plugging and abandonment
liabilities.
|
On
September 11, 2007, the Bankruptcy Court approved the PTRA. The PTRA
did not resolve the open issues on the Non-Consent Properties and certain other
properties.
Notwithstanding
the PTRA, as a result of Calpine’s bankruptcy, there remains the possibility
that there will be issues between us and Calpine that could amount to material
contingencies in relation to the litigation filed by Calpine against us or the
Purchase Agreement, including unasserted claims and assessments with respect to
(i) Calpine’s remaining performance under the Purchase Agreement and the amounts
that will be payable in connection therewith, (ii) whether or not Calpine and
its affiliated debtors will, in fact, perform their remaining obligations in
connection with the Purchase Agreement and PTRA; and (iii) the issues pertaining
to the Non-Consent Properties.
Arbitration
between Calpine/Rosetta and Pogo Producing Company
On
September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico
oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course
of that sale, Pogo made three title defect claims on properties sold by Calpine
(valued at approximately $2.7 million in the aggregate, subject to a $0.5
million deductible assuming no reconveyance) claiming that certain leases
subject to the sale had expired because of lack of production. With Rosetta’s
assistance, Calpine had undertaken without success to resolve this matter by
obtaining ratifications of a majority of the questionable leases. Calpine filed
for bankruptcy protection before Pogo filed arbitration against it. Even though
this is a retained liability of Calpine, Calpine had earlier declined to accept
the Company’s tender of defense and indemnity when Pogo filed for arbitration
against us. We filed a motion to stay this arbitration under the
automatic stay provision of the Bankruptcy Code which motion was granted by the
Bankruptcy Court on April 24, 2007. We intend to cooperate with Calpine in
defending against Pogo’s claim should it resume; however, it is too early for
management to determine whether this matter will affect us, and if so,
in what amount. This is due, but not limited to uncertainty
concerning (i) whether or not Pogo’s proofs of claim will be fully satisfied by
Calpine under its approved Plan of Reorganization; and (ii) whether and if so,
the extent to which, Calpine may reimburse us for our claim for our defense
costs and any arbitration award regarding the Pogo claim. We have
entered into a joint defense agreement with Calpine whereby Calpine has taken
over the defense of Pogo’s claims and is indemnifying us.
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.
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 March 31, 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
|
|
January
1 - January 31
|
|
|
2,766 |
|
|
$ |
19.83 |
|
|
|
- |
|
|
|
- |
|
February
1 - February 29
|
|
|
3,958 |
|
|
|
19.57 |
|
|
|
- |
|
|
|
- |
|
March
1 - March 31
|
|
|
2,244 |
|
|
|
20.61 |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
8,968 |
|
|
$ |
19.91 |
|
|
|
- |
|
|
|
- |
|
(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: May
9, 2008
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
|