Form 10-Q 9/30/2006
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
[X]
|
Quarterly
Report Pursuant To Section 13 or 15(d) of The Securities Exchange
Act of
1934
|
For
The Quarterly Period Ended September 30, 2006
OR
[
] Transition
Report Pursuant To Section 15(d) of The Securities Exchange Act of
1934
Commission
File Number: 000-51801
ROSETTA
RESOURCES INC.
(Exact
name of registrant as specified in its charter)
|
|
Delaware
|
43-2083519
|
(State
or other jurisdiction of incorporation or
organization)
|
(I.R.S.
Employer Identification No.)
|
|
|
717
Texas, Suite 2800, Houston, TX
|
77002
|
(Address
of principal executive offices)
|
(Zip
Code)
|
|
|
Registrant's
telephone number, including area code: (713)
335-4000
|
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. Yes [X] No [ ]
Indicate
by check mark whether the Registrant is a large accelerated filer, an
accelerated filer or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Securities Exchange Act
of 1934. Large accelerated filer [ ] Accelerated filer [ ] Non-Accelerated
filer
[X]
Indicate
by check mark whether the registrant is a shell company (as defined by Rule
12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]
The
number of shares of the registrant's Common Stock, $.001 par value per share,
outstanding as of November 2, 2006 was 50,647,319.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
22
|
|
|
30
|
|
|
30
|
|
|
32
|
|
|
32
|
|
|
33
|
|
|
36
|
|
|
36
|
|
|
36
|
|
|
36
|
|
|
37
|
|
|
38
|
|
39
|
|
|
|
|
|
|
Rosetta
Resources Inc.
Consolidated
Balance Sheet
(In
thousands, except share amounts)
|
|
September
30,
2006
|
|
December
31,
2005
|
|
Assets
|
|
(Unaudited)
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
78,743
|
|
$
|
99,724
|
|
Restricted
cash
|
|
|
15,000
|
|
|
-
|
|
Accounts
receivable
|
|
|
34,751
|
|
|
40,051
|
|
Derivative
instruments
|
|
|
23,591
|
|
|
1,110
|
|
Deferred
income taxes
|
|
|
-
|
|
|
10,962
|
|
Income
tax receivable
|
|
|
-
|
|
|
6,000
|
|
Other
current assets
|
|
|
9,696
|
|
|
9,411
|
|
Total
current assets
|
|
|
161,781
|
|
|
167,258
|
|
Oil
and natural gas properties, full cost method, of which $51.0 million
at
September 30,
2006
and $30.6 million at December 31, 2005 were excluded from amortization
|
|
|
1,134,754
|
|
|
973,185
|
|
Other
|
|
|
3,868
|
|
|
2,912
|
|
|
|
|
1,138,622
|
|
|
976,097
|
|
Accumulated
depreciation, depletion, and amortization
|
|
|
(117,186
|
)
|
|
(40,161
|
)
|
Total
property and equipment, net
|
|
|
1,021,436
|
|
|
935,936
|
|
Deferred
loan fees
|
|
|
3,670
|
|
|
4,555
|
|
Deferred
income taxes
|
|
|
-
|
|
|
8,594
|
|
Other
assets
|
|
|
3,458
|
|
|
2,926
|
|
|
|
|
7,128
|
|
|
16,075
|
|
Total
assets
|
|
$
|
1,190,345
|
|
$
|
1,119,269
|
|
|
|
|
|
|
|
|
|
Liabilities
and Stockholders' Equity
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
16,604
|
|
$
|
13,442
|
|
Accrued
liabilities
|
|
|
42,604
|
|
|
28,397
|
|
Royalties
payable
|
|
|
13,479
|
|
|
15,511
|
|
Derivative
instruments
|
|
|
-
|
|
|
29,957
|
|
Prepayment
on gas sales
|
|
|
10,599
|
|
|
14,528
|
|
Deferred
income taxes
|
|
|
8,965
|
|
|
-
|
|
Total
current liabilities
|
|
|
92,251
|
|
|
101,835
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
Derivative
instruments
|
|
|
7,952
|
|
|
52,977
|
|
Long-term
debt
|
|
|
240,000
|
|
|
240,000
|
|
Asset
retirement obligation
|
|
|
9,698
|
|
|
9,034
|
|
Deferred
income taxes
|
|
|
28,179
|
|
|
-
|
|
Total
liabilities
|
|
|
378,080
|
|
|
403,846
|
|
Commitments
and contingencies (Note 10)
|
|
|
|
|
|
|
|
Stockholders'
equity:
|
|
|
|
|
|
|
|
Common
stock, $0.001 par value, 150,000,000 shares authorized; 50,380,475
issued
|
|
|
50
|
|
|
50
|
|
Additional
paid-in capital
|
|
|
754,002
|
|
|
748,569
|
|
Treasury
stock, at cost; 83,881 and no shares at September 30, 2006 and
December
31, 2005, respectively
|
|
|
(1,526
|
)
|
|
-
|
|
Accumulated
other comprehensive income (loss)
|
|
|
10,792
|
|
|
(50,731
|
)
|
Retained
earnings
|
|
|
48,947
|
|
|
17,535
|
|
Total
stockholders' equity
|
|
|
812,265
|
|
|
715,423
|
|
Total
liabilities and stockholders' equity
|
|
$
|
1,190,345
|
|
$
|
1,119,269
|
|
|
|
|
|
|
|
|
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated/Combined
Statement of Operations
(In
thousands, except per share amounts)
(Unaudited)
|
|
Successor-Consolidated
|
|
Successor-Consolidated
|
|
|
Predecessor-Combined
|
|
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
|
2005
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales
|
|
$
|
61,366
|
|
$
|
51,661
|
|
$
|
171,783
|
|
|
$
|
13,713
|
|
Oil
sales
|
|
|
9,831
|
|
|
6,204
|
|
|
27,339
|
|
|
|
8,166
|
|
Oil
and natural gas sales to affiliates
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
81,952
|
|
Total
revenues
|
|
|
71,197
|
|
|
57,865
|
|
|
199,122
|
|
|
|
103,831
|
|
Operating
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense
|
|
|
9,449
|
|
|
8,849
|
|
|
27,330
|
|
|
|
16,629
|
|
Depreciation,
depletion, and amortization
|
|
|
27,906
|
|
|
21,720
|
|
|
77,574
|
|
|
|
30,679
|
|
Exploration
expense
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
2,355
|
|
Dry
hole costs
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
1,962
|
|
Treating
and transportation
|
|
|
317
|
|
|
552
|
|
|
2,043
|
|
|
|
1,998
|
|
Affiliated
marketing fees
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
913
|
|
Marketing
fees
|
|
|
526
|
|
|
678
|
|
|
1,634
|
|
|
|
-
|
|
Production
taxes
|
|
|
2,153
|
|
|
1,946
|
|
|
5,476
|
|
|
|
2,755
|
|
General
and administrative costs
|
|
|
8,316
|
|
|
6,880
|
|
|
24,645
|
|
|
|
9,677
|
|
Total
operating costs and expenses
|
|
|
48,667
|
|
|
40,625
|
|
|
138,702
|
|
|
|
66,968
|
|
Operating
income
|
|
|
22,530
|
|
|
17,240
|
|
|
60,420
|
|
|
|
36,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
(income) expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense with affiliates, net of interest capitalized
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
6,995
|
|
Interest
expense, net of interest capitalized
|
|
|
4,557
|
|
|
4,077
|
|
|
13,060
|
|
|
|
-
|
|
Interest
(income) expense
|
|
|
(1,099
|
)
|
|
(874
|
)
|
|
(3,351
|
)
|
|
|
(516
|
)
|
Other
(income) expense, net
|
|
|
(171
|
)
|
|
153
|
|
|
6
|
|
|
|
207
|
|
Total
other expense
|
|
|
3,287
|
|
|
3,356
|
|
|
9,715
|
|
|
|
6,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before provision for income taxes
|
|
|
19,243
|
|
|
13,884
|
|
|
50,705
|
|
|
|
30,177
|
|
Provision
for income taxes
|
|
|
7,321
|
|
|
5,677
|
|
|
19,293
|
|
|
|
11,496
|
|
Net
income
|
|
$
|
11,922
|
|
$
|
8,207
|
|
$
|
31,412
|
|
|
$
|
18,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.24
|
|
$
|
0.16
|
|
$
|
0.63
|
|
|
$
|
0.37
|
|
Diluted
|
|
$
|
0.24
|
|
$
|
0.16
|
|
$
|
0.62
|
|
|
$
|
0.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
50,282
|
|
|
50,000
|
|
|
50,211
|
|
|
|
50,000
|
|
Diluted
|
|
|
50,426
|
|
|
50,160
|
|
|
50,384
|
|
|
|
50,160
|
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated/Combined
Statement of Cash Flows
(In
thousands)
(Unaudited)
|
|
Successor-Consolidated
|
|
Successor-Consolidated
|
|
|
Predecessor-Combined
|
|
|
|
Nine
Months Ended September 30,
|
|
Three
Months Ended September 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2006
|
|
2005
|
|
|
2005
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
31,412
|
|
$
|
8,207
|
|
|
$
|
18,681
|
|
Adjustments
to reconcile net income to net cash from operating
activities
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
77,574
|
|
|
21,720
|
|
|
|
30,679
|
|
Affiliate
interest expense
|
|
|
-
|
|
|
-
|
|
|
|
(6,995
|
)
|
Deferred
income taxes
|
|
|
18,991
|
|
|
3,406
|
|
|
|
2,874
|
|
Amortization
of deferred loan fees recorded as interest expense
|
|
|
885
|
|
|
-
|
|
|
|
-
|
|
Income
from unconsolidated investments
|
|
|
(168
|
)
|
|
(112
|
)
|
|
|
(161
|
)
|
Stock
compensation expense
|
|
|
4,348
|
|
|
1,710
|
|
|
|
-
|
|
Other
non-cash charges
|
|
|
-
|
|
|
-
|
|
|
|
99
|
|
Change
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
5,300
|
|
|
(33,570
|
)
|
|
|
2,378
|
|
Accounts
receivable from affiliates
|
|
|
-
|
|
|
-
|
|
|
|
6,298
|
|
Income
taxes receivable
|
|
|
6,000
|
|
|
-
|
|
|
|
-
|
|
Other
assets
|
|
|
1,070
|
|
|
(5,412
|
)
|
|
|
2,563
|
|
Accounts
payable
|
|
|
2,494
|
|
|
24,098
|
|
|
|
(4,494
|
)
|
Accrued
liabilities
|
|
|
(324
|
)
|
|
8,019
|
|
|
|
241
|
|
Royalties
payable
|
|
|
(5,961
|
)
|
|
32,913
|
|
|
|
(1,406
|
)
|
Income
taxes payable
|
|
|
-
|
|
|
2,271
|
|
|
|
8,622
|
|
Net
cash provided by operating activities
|
|
|
141,621
|
|
|
63,250
|
|
|
|
59,379
|
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition,
net of cash acquired
|
|
|
-
|
|
|
(910,064
|
)
|
|
|
-
|
|
Purchases
of property and equipment
|
|
|
(147,243
|
)
|
|
(26,507
|
)
|
|
|
(32,202
|
)
|
Disposals
of property and equipment
|
|
|
36
|
|
|
-
|
|
|
|
1,447
|
|
Deposits
|
|
|
50
|
|
|
(201
|
)
|
|
|
-
|
|
Investment
in non-affiliated subsidiary
|
|
|
-
|
|
|
(820
|
)
|
|
|
-
|
|
Increase
in restricted cash
|
|
|
(15,000
|
)
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
(4
|
)
|
|
-
|
|
|
|
110
|
|
Net
cash used in investing activities
|
|
|
(162,161
|
)
|
|
(937,592
|
)
|
|
|
(30,645
|
)
|
Cash
flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
Equity
offering proceeds
|
|
|
-
|
|
|
800,000
|
|
|
|
-
|
|
Equity
offering transaction fees
|
|
|
268
|
|
|
(53,540
|
)
|
|
|
-
|
|
Borrowings
on term loan
|
|
|
-
|
|
|
100,000
|
|
|
|
-
|
|
Payments
on term loan
|
|
|
-
|
|
|
(25,000
|
)
|
|
|
-
|
|
Borrowings
on revolving credit facility
|
|
|
-
|
|
|
225,000
|
|
|
|
-
|
|
Payments
on revolving credit facility
|
|
|
-
|
|
|
(60,000
|
)
|
|
|
-
|
|
Loan
fees
|
|
|
-
|
|
|
(5,145
|
)
|
|
|
-
|
|
Notes
payable to affiliates
|
|
|
-
|
|
|
-
|
|
|
|
(27,239
|
)
|
Proceeds
from issuances of common stock
|
|
|
515
|
|
|
-
|
|
|
|
-
|
|
Stock-based
compensation excess tax benefit
|
|
|
302
|
|
|
-
|
|
|
|
-
|
|
Purchases
of treasury stock
|
|
|
(1,526
|
)
|
|
-
|
|
|
|
-
|
|
Net
cash (used in) provided by financing activities
|
|
|
(441
|
)
|
|
981,315
|
|
|
|
(27,239
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash
|
|
|
(20,981
|
)
|
|
106,973
|
|
|
|
1,495
|
|
Cash
and cash equivalents, beginning of period
|
|
|
99,724
|
|
|
-
|
|
|
|
-
|
|
Cash
and cash equivalents, end of period
|
|
$
|
78,743
|
|
$
|
106,973
|
|
|
$
|
1,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures included in accrued liabilities
|
|
$
|
3,783
|
|
|
(1,670
|
)
|
|
|
-
|
|
Accrued
purchase price adjustment |
|
|
11,400 |
|
|
|
|
|
|
|
|
The
accompanying notes to the financial statements are an integral part
hereof
Rosetta
Resources Inc.
Notes
to Consolidated/Combined Financial Statements (unaudited)
(1)
|
Organization
and Operations of the
Company
|
Nature
of Operations. Rosetta
Resources Inc. (together with its consolidated subsidiaries, “the Company”) was
formed in June 2005. The Company (“Successor”) is engaged in oil and natural gas
exploration, development, production, and acquisition activities in the United
States. The Company’s main operations are primarily concentrated in the
Sacramento Basin of California, the Lobo and Perdido Trends in South Texas,
the
Gulf of Mexico and the Rocky Mountains.
These
interim financial statements have not been audited. However, in the opinion
of
management, all adjustments, consisting of only normal recurring adjustments,
necessary for a fair presentation of the financial statements have been
included. Results of operations for interim periods are not necessarily
indicative of the results of operations that may be expected for the entire
year. In addition, these financial statements have been prepared in accordance
with the instructions to Form 10-Q and, therefore, do not include all
disclosures required for financial statements prepared in conformity with
accounting principles generally accepted in the United States of America.
These
financial statements and notes should be read in conjunction with the Company’s
audited consolidated/combined financial statements and the notes thereto
included in the Company’s Annual Report on Form 10-K for the year ended December
31, 2005.
Certain
reclassifications of prior year balances have been made to conform such amounts
to corresponding 2006 classifications. These reclassifications have no impact
on
net income.
(2)
|
Acquisition
of Calpine Oil and Natural Gas
Business
|
On
July
7, 2005, the Company acquired substantially all of the oil and natural gas
business of Calpine Corporation and certain of its subsidiaries (collectively,
“Calpine” or “Predecessor”), excluding certain non-consent properties described
below, for approximately $910 million. This acquisition (the “Acquisition”) was
funded with the issuance of common stock totaling $725 million and $325 million
of debt from the Company’s credit facilities. The transaction was accounted for
under the purchase method in accordance with Statement of Financial Accounting
Standards (“SFAS”) No.141. The results of operations were included in the
Company’s financial statements effective July 1, 2005 as the operating results
in the intervening period were not significant. The purchase price in the
Acquisition was calculated as follows (In thousands):
Cash
from equity offering
|
|
$
|
725,000
|
|
Proceeds
from revolver
|
|
|
225,000
|
|
Proceeds
from term loan
|
|
|
100,000
|
|
Other
purchase price costs
|
|
|
(53,389
|
)
|
Transaction
adjustments (purchase price adjustments)
|
|
|
(11,556
|
)
|
Transaction
adjustments (non-consent properties)
|
|
|
(74,991
|
)
|
Initial
purchase price
|
|
$
|
910,064
|
|
|
|
|
|
|
Other
purchase price costs relate primarily to professional fees of $3.9 million
and
other direct transaction costs of $49.5 million.
The
transaction adjustments (purchase price adjustments) referred to above are
an
amount agreed upon by Calpine and the Company to cover potential costs and/or
revenues to be adjusted to actual upon the final settlement.
Transaction
adjustments (non-consent properties) referred to above relate to properties
which Calpine determined required third party consents or waivers of
preferential purchase rights in order to effect the transfer of title from
Calpine to the Company or to Calpine entities acquired by the Company in the
Acquisition (collectively, “Non-Consent Properties”). At July 7, 2005, the
Company withheld approximately $75 million of the purchase price with respect
to
the Non-Consent Properties. A third party exercised a preferential right to
purchase certain Non-Consent Properties. Assuming such preferential rights
transaction is consummated, these properties will not be conveyed to the
Company, and the purchase price of the remaining Non-Consent properties will
be
reduced by approximately $7.4 million. Despite Calpine’s bankruptcy filing,
management believes that it remains likely that conveyance to the Company of
substantially all of the remaining Non-Consent Properties will occur. Upon
conveyance of the remaining Non-Consent Properties, approximately $68 million,
the balance of the additional purchase price, will be paid to Calpine and will
be incremental to the purchase price of $910 million. The Company has excluded
the effects of the operating results for the Non-Consent Properties from the
Company’s actual results for the three and nine months ended September 30, 2006.
If the assignment of the remaining Non-Consent
Properties does not occur, the portion of the purchase price the Company
withheld pending obtaining consent or waivers for these properties will be
available to the Company for general corporate purposes or to acquire other
properties.
The
following is the allocation of the purchase price to specific assets acquired
and liabilities assumed based on estimates of the fair values and costs (In
thousands). There was no goodwill associated with the transaction.
Current
assets
|
|
$
|
1,794
|
|
Non-current
assets
|
|
|
5,087
|
|
Properties,
plant and equipment
|
|
|
925,141
|
|
Current
liabilities
|
|
|
(14,390
|
)
|
Long-term
liabilities
|
|
|
(7,568
|
)
|
|
|
$
|
910,064
|
|
|
|
|
|
|
The
purchase price allocation is based upon the manner in which the parties expect
to resolve the negotiation associated with the Company’s revised Final
Settlement Statement pertaining to the Acquisition that was delivered to Calpine
on May 12, 2006. In addition to the $68 million that will be payable to Calpine
if and when title is obtained by the Company for the remaining Non-Consent
Properties and Calpine provides the further assurances to eliminate any open
issues on title to the remaining properties that may require further
documentation, the Company’s revised Final Settlement Statement includes the
proposed cash payment to Calpine of approximately $11 million arising from
net
revenues that were estimated and withheld at the closing of the Acquisition,
which is recorded as an accrued liability on the Consolidated Balance Sheet
as of September 30, 2006.
The
unaudited pro forma information for the nine months ended September 30, 2005
assumes the acquisition of Calpine’s domestic oil and natural gas business and
the related financings occurred on January 1, 2004. The Company believes
the assumptions used provide a reasonable basis for presenting the significant
effects directly attributable to such transactions. The unaudited pro forma
financial statements do not purport to represent what the Company’s results of
operations would have been if such transactions had occurred on such date.
|
|
Nine
Months Ended
September
30, 2005
|
|
|
|
(In
thousands, except per share amounts)
|
|
|
|
(Unaudited)
|
|
Revenues
|
|
$
|
152,262
|
|
Net
income
|
|
|
17,109
|
|
Basic
earnings per common share
|
|
|
0.34
|
|
Diluted
earnings per common share
|
|
$
|
0.34
|
|
(3)
|
Summary
of Significant Accounting
Policies
|
The
Company has provided discussion of significant accounting policies, estimates
and judgments in its Annual Report on Form 10-K for the year ended December
31,
2005.
Principles
of Consolidation/Combination and Basis of Presentation. The
Predecessor combined financial statements for the six months ended June 30,
2005
have been prepared from the historical accounting records of the domestic oil
and natural gas business of Calpine and are presented on a carve-out basis
to
include the historical operations of the domestic oil and natural gas business.
The domestic oil and natural gas business of Calpine was separately accounted
for and managed through direct and indirect subsidiaries of Calpine. The
combined financial information included herein includes certain allocations
based on the historical activity levels to reflect the combined financial
statements in accordance with accounting principles generally accepted in the
United States of America and may not necessarily reflect the financial position,
results of operations and cash flows of the Company in the future or as if
the
Company had existed as a separate, stand-alone business during the period
presented. The allocations consist of general and administrative expenses such
as employee payroll and related benefit costs and building lease expense, which
were incurred on behalf of Calpine. The allocations have been made on a
reasonable basis and have been consistently applied for the periods presented.
The
accompanying consolidated financial statements as of September 30, 2006 and
December 31, 2005 and for the three and nine months ended September 30, 2006
and
three months ended September 30, 2005 contain the accounts of Rosetta Resources
Inc. and its majority owned subsidiaries after eliminating all significant
intercompany balances and transactions.
Stock-Based
Compensation.
On
January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based
Payments” (“SFAS No. 123R”). This statement applies to all awards granted,
modified, repurchased or cancelled after January 1, 2006 and to the unvested
portion of all awards granted prior to that date. The Company adopted this
statement using the modified version of the prospective application (modified
prospective application). Under the modified prospective application,
compensation cost for the portion of awards for which the employee’s requisite
service has not been rendered that are outstanding as of January 1, 2006 must
be
recognized as the requisite service is rendered on or after that date. The
compensation cost for that portion of awards shall be based on the original
fair
market value of those awards on the date of grant as calculated for recognition
under SFAS No. 123 “Accounting for Stock-Based Compensation” as amended by SFAS
No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure”
(“SFAS No. 123”). The compensation cost for these earlier awards shall be
attributed to periods beginning on or after January 1, 2006 using the
attribution method that was used under SFAS 123.
The
adoption of the new standard did not have a significant impact on the
Consolidated Balance Sheet because of the requirement to decrease retained
earnings with an offsetting increase in additional paid-in capital. On the
Consolidated/Combined Statement of Operations, the adoption of SFAS No. 123R
resulted in decreases in both income before income taxes and net income of
$1.0
million and $0.6 million, respectively, for the three months ended September
30,
2006 and $4.3 million and $2.7 million, respectively, for the nine months ended
September 30, 2006. The effect on net income per share for basic and diluted
was
a reduction $0.01 and $0.05 for the three and nine months ended September 30,
2006, respectively. See Note 12
of the
notes to the Consolidated/Combined Financial Statements for additional
disclosure.
Prior
to
the adoption of SFAS No. 123R, the Company presented all tax benefit deductions
resulting from the exercise of stock options as operating cash flows in the
accompanying Consolidated/Combined Statement of Cash Flows. SFAS No. 123R
requires the cash flows that result from tax deductions in excess of the
compensation expense recognized as an operating expense in 2006 and reported
in
pro forma disclosures prior to 2006 for those stock options (excess tax
benefits) to be classified as financing cash flows. The excess tax benefit
for
the nine months ended September 30, 2006 was $0.3 million.
Recent
Accounting Developments
Accounting
Changes and Error Corrections.
In May
2005, the Financial Accounting Standards Board (“FASB”) issued SFAS
No. 154, “Accounting Changes and Error Corrections - a replacement of
Accounting Principles Board Opinion (“APB”) No. 20 and FASB Statement
No. 3” (“SFAS No. 154”), which changes the requirements for the accounting
for and the reporting of a change in accounting principle. This Statement
applies to all voluntary changes in accounting principles. It also applies
to
changes required by an accounting pronouncement in the unusual instance that
the
pronouncement does not include specific transition provisions. When a
pronouncement includes specific transition provisions, those provisions should
be followed. SFAS No. 154 is effective for accounting changes and corrections
of
errors made in fiscal years beginning after December 15, 2005. The adoption
of this Statement did not impact the Company’s consolidated financial position,
results of operations, or cash flows.
Accounting
for Certain Hybrid Financial Instruments.
In
February 2006 , the FASB issued SFAS No. 155, “Accounting for Certain Hybrid
Instruments - an amendment of FASB Statements 133 and 140”,
which
is
effective for all financial instruments acquired or issued after the beginning
of an entity’s first fiscal year that begins after September 15,
2006.
The
statement improves financial reporting by eliminating the exemption from
applying SFAS No. 133 to interests in securitized financial assets so that
similar instruments are accounted for similarly regardless of the form of the
instruments. The statement also improves financial reporting by allowing a
preparer to elect fair value measurement at acquisition, at issuance, or when
a
previously recognized financial instrument is subject to a re-measurement event,
on an instrument-by-instrument basis, in cases in which a derivative would
otherwise have to be bifurcated, if the holder elects to account for the whole
instrument on a fair value basis. The adoption of this statement is not expected
to have a material impact on the Company’s consolidated financial position,
results of operations, or cash flows.
Accounting
for Uncertainty in Income Taxes. In
June
2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in
Income Taxes - an interpretation of FASB Statement No. 109” (“FIN
48”). This interpretation provides guidance for recognizing and measuring
uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income
Taxes.” FIN 48 prescribes a threshold condition that a tax position must meet
for any of the benefit of the uncertain tax position to be recognized in the
financial statements. Guidance is also provided regarding derecognition,
classification and disclosure of these uncertain tax positions. FIN 48 is
effective for fiscal years beginning after December 15, 2006. The adoption
of this Interpretation is not expected to have a material impact on the
Company’s consolidated financial position, results of operations, or cash
flows.
Guidance
for Quantifying Financial Statement Misstatement.
In
September 2006, the Securities and Exchange Commission (“SEC”) issued Staff
Accounting Bulletin No. 108, “Considering the Effects of Prior Year
Misstatements when Quantifying Misstatements in Current Year Financial
Statements” (“SAB 108”), which establishes an approach requiring the
quantification of financial statement errors based on the effect of the error
on
each of the company’s financial statements and the related financial statement
disclosures. This model is commonly referred to as a “dual approach”
because it requires quantification of errors under both the “iron curtain” and
“roll-over” methods. The
roll-over
method focuses primarily on the impact of a misstatement on the income
statement, including the reversing effect of prior year misstatements; however,
its use can lead to the accumulation of misstatements in the balance sheet.
The
iron curtain method focuses primarily on the effect of correcting the period
end
balance sheet with less emphasis on the reversing effects of prior year errors
on the income statement. The Company currently uses the iron curtain method
for
quantifying financial statement misstatements. The Company will initially apply
the provisions of SAB 108 in connection with the preparation of the Company’s
annual financial statements for the year ending December 31, 2006. The use
of
the dual approach is not expected to have a material impact on the Company’s
consolidated financial position, results of operations, or cash
flows.
Fair
Value Measurements.
In
September 2006, the FASB issued FASB Statement 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. Although the disclosure
requirements may be expanded where certain assets or liabilities are fair valued
such as those related to stock compensation expense and hedging activities,
the
Company does not expect the adoption of SFAS No. 157 to have a material impact
on the Company’s consolidated financial position, results of operations, or cash
flows.
In
July
2006, the Company entered
into a Deposit Account Control Agreement in order to provide a security interest
under the terms of its senior
secured revolving line of credit.
Under the terms of the Deposit Account Control Agreement, the Company was
required to maintain $15.0 million on account to
keep a
borrowing base of $325.0 million.
The
Company’s borrowing base is
subject to review on a semi-annual basis under
the
terms of the senior
secured revolving line of credit.
Based on this semi-annual review,
a
consent agreement was signed in October 2006
in which
the borrowing base remained at $325.0 million and the
Company was no
longer
required to maintain the $15.0 million balance pursuant to the Deposit Account
Control Agreement.
(5)
|
Property,
Plant and Equipment
|
In
connection with the Company’s separation from Calpine, the Company adopted the
full cost method of accounting for oil and natural gas properties beginning
July 1, 2005. Under the full cost method, all costs incurred in acquiring,
exploring and developing properties within a relatively large geopolitical
cost
center are capitalized when incurred and are amortized as mineral reserves
in
the cost center are produced, subject to a limitation that the capitalized
costs
not exceed the value of those reserves. In some cases, however, certain
significant costs, such as those associated with offshore U.S. operations,
are
deferred separately without amortization until the specific property to which
they relate is found to be either productive or nonproductive, at which time
those deferred costs and any reserves attributable to the property are included
in the computation of amortization in the cost center. All costs incurred in
oil
and natural gas producing activities are regarded as integral to the
acquisition, discovery and development of whatever reserves ultimately result
from the efforts as a whole, and are thus associated with the Company’s
reserves. The Company capitalizes internal costs directly identified with
acquisition, exploration and development activities. The Company capitalized
$0.9 million and $2.6 million of internal costs for the three and nine months
ended September 30, 2006, respectively. Unevaluated costs are excluded from
the
full cost pool and are periodically evaluated for impairment rather than
amortized. Upon evaluation, costs associated with productive properties are
transferred to the full cost pool and amortized. Gains or losses on the sale
of
oil and natural gas properties are generally included in the full cost pool
unless a significant portion of the pool is sold.
The
Company assesses the impairment for oil and natural gas properties for the
full
cost pool quarterly using a ceiling test to determine if impairment is
necessary. If the net capitalized costs of oil and natural gas properties exceed
the cost center ceiling, the Company is 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.
The
Company’s ceiling test computation was calculated using hedge adjusted market
prices at September 30, 2006 which were based on a Henry Hub gas price of $4.18
per MMBtu and a West Texas Intermediate oil price of $62.91 per barrel. The
use
of these prices indicated a writedown of $142.1 million at September 30, 2006.
Cash flow hedges of natural gas production in place at September 30, 2006
increased the calculated ceiling value by approximately $92.2 million (net
of
tax). However, subsequent to September 30, 2006 the market price for Henry
Hub
increased to $7.42 per MMBtu and the price for West Texas Intermediate decreased
to $58.07 per barrel, and utilizing these prices, the Company’s net capitalized
costs of oil and natural gas properties exceeded the ceiling amount. As a result
no writedown was recorded for the quarter ended September 30, 2006. The ceiling
value calculated using subsequent prices includes approximately $17.9 million
related to the positive effects of future cash flow hedges of natural gas
production. Due to the volatility of commodity prices, should natural gas and
oil prices decline in the future, it is possible that a writedown could
occur.
Calpine
followed the successful efforts method of accounting for oil and natural gas
activities. Under the successful efforts method, lease acquisition costs and
all
development costs were capitalized. Exploratory drilling costs were capitalized
until the results were determined. If proved reserves were not discovered,
the
exploratory drilling costs were expensed. Other exploratory costs were expensed
as incurred. Interest costs related to financing major oil and natural gas
projects in progress were capitalized until the projects were evaluated or
until
the projects were substantially complete and ready for their intended use if
the
projects were evaluated as successful. Calpine also capitalized internal costs
directly identified with acquisition, exploration and development activities
and
did not include any costs related to production, general corporate overhead
or
similar activities. The provision for depreciation, depletion, and amortization
was based on the capitalized costs as determined above, plus future abandonment
costs net of salvage value, using the unit of production method with lease
acquisition costs amortized over total proved reserves and other costs amortized
over proved developed reserves.
The
Company’s total property, plant and equipment consists of the
following:
|
|
September
30,
2006
|
|
December
31,
2005
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$
|
1,103,302
|
|
$
|
951,968
|
|
Unproved
properties
|
|
|
31,452
|
|
|
21,217
|
|
Other
|
|
|
3,868
|
|
|
2,912
|
|
Total
|
|
|
1,138,622
|
|
|
976,097
|
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(117,186
|
)
|
|
(40,161
|
)
|
|
|
$
|
1,021,436
|
|
$
|
935,936
|
|
|
|
|
|
|
|
|
|
Included
in the Company’s oil and natural gas properties are asset retirement obligations
of $9.2 million and $9.1 million as of September 30, 2006 and December 31,
2005,
respectively.
At
September 30, 2006 and December 31, 2005, the Company excluded the following
capitalized costs from depreciation, depletion and amortization:
|
|
September
30,
2006
|
|
December
31,
2005
|
|
Onshore:
|
|
(In
thousands)
|
Development
cost
|
|
$
|
13,796
|
|
$
|
1,716
|
|
Exploration
cost
|
|
|
3,939
|
|
|
5,212
|
|
Acquisition
cost of undeveloped acreage
|
|
|
25,696
|
|
|
19,684
|
|
Capitalized
interest
|
|
|
1,691
|
|
|
555
|
|
Total
|
|
|
45,122
|
|
|
27,167
|
|
|
|
|
|
|
|
|
|
Offshore:
|
|
|
|
|
|
|
|
Development
cost
|
|
$
|
1,779
|
|
$
|
-
|
|
Exploration
cost
|
|
|
-
|
|
|
2,407
|
|
Acquisition
cost of undeveloped acreage
|
|
|
3,954
|
|
|
950
|
|
Capitalized
interest
|
|
|
111
|
|
|
28
|
|
Total
|
|
|
5,844
|
|
|
3,385
|
|
|
|
|
|
|
|
|
|
Total
costs excluded from depreciation, depletion, and
amortization
|
|
$
|
50,966
|
|
$
|
30,552
|
|
|
|
|
|
|
|
|
|
In
April
2006, the Company acquired certain oil and gas producing non-operated properties
located in Duval, Zapata, and Jim Hogg Counties, Texas and Escambia County
in
Alabama from Contango Oil and Gas for $11.6 million in cash.
(6)
|
Commodity
Hedging Contracts and Other Derivatives
|
In
the
third quarter of 2006, the Company entered into two additional financial fixed
price swaps with prices ranging from $7.99 per MMBtu to $8.23 per MMBtu covering
a portion of the Company’s 2007 and 2008 production. The following financial
fixed price swaps were outstanding with average underlying prices that represent
hedged prices of commodities at various market locations at September 30,
2006:
Settlement
Period
|
|
Derivative
Instrument
|
|
Hedge
Strategy
|
|
Notional
Daily Volume
MMBtu
|
|
Total
of Notional Volume
MMBtu
|
|
Average
Underlying Prices
MMBtu
|
|
Total
of Proved Natural Gas Production Hedged (1)
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
2006
|
|
|
Swap
|
|
|
Cash
flow
|
|
|
45,000
|
|
|
4,140,000
|
|
$
|
7.92
|
|
|
46
|
%
|
$
|
11,176
|
|
2007
|
|
|
Swap
|
|
|
Cash
flow
|
|
|
45,341
|
|
|
16,549,500
|
|
|
7.87
|
|
|
41
|
%
|
|
7,593
|
|
2008
|
|
|
Swap
|
|
|
Cash
flow
|
|
|
39,909
|
|
|
14,606,616
|
|
|
7.63
|
|
|
35
|
%
|
|
(2,060
|
)
|
2009
|
|
|
Swap
|
|
|
Cash
flow
|
|
|
26,141
|
|
|
9,541,465
|
|
|
6.99
|
|
|
26
|
%
|
|
(4,398
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
44,837,581
|
|
|
|
|
|
|
|
$
|
12,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Estimated based on net gas reserves presented in the December 31, 2005
Netherland, Sewell, & Associates, Inc. reserve report.
In
the
third quarter of 2006, the Company entered into two additional costless collar
transactions with an average floor price of $7.19 per MMBtu and an average
ceiling price of $10.03 per MMBtu covering a portion of the Company’s 2007
production. The following costless collar transactions were outstanding with
associated notional volumes and contracted ceiling and floor prices that
represent hedge prices at various market locations at September 30,
2006:
Settlement
Period
|
|
Derivative
Instrument
|
|
Hedge
Strategy
|
|
Notional
Daily Volume
MMBtu
|
|
Total
of Notional Volume
MMBtu
|
|
Average
Floor Price
MMBtu
|
|
Average
Ceiling Price
MMBtu
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
Costless
Collar
|
|
|
Cash
flow
|
|
|
10,000
|
|
|
920,000
|
|
$
|
8.83
|
|
$
|
14.00
|
|
$
|
3,175
|
|
2007
|
|
|
Costless
Collar
|
|
|
Cash
flow
|
|
|
10,000
|
|
|
3,650,000
|
|
|
7.19
|
|
$
|
10.03
|
|
|
1,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,570,000
|
|
|
|
|
|
|
|
$
|
5,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
total
of proved natural gas production hedged in 2006 and 2007 for the costless
collars is approximately 10% and 9%, respectively, based on the December 31,
2005 reserve report prepared by Netherland, Sewell, & Associates,
Inc.
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 September
30, 2006, the Company made no deposits for collateral.
The
following table sets forth the results of third party hedge transactions for
the
respective period for the Consolidated Statement of Operations:
|
|
Three
Months Ended September 30, 2006
|
|
Nine
Months Ended September 30, 2006
|
|
Natural
Gas
|
|
|
|
|
|
|
|
Quantity
settled (MMBtu)
|
|
|
5,060,000
|
|
|
15,015,000
|
|
Increase
in natural gas sales revenue (In thousands)
|
|
$
|
9,114
|
|
$
|
19,804
|
|
The
Company expects to reclassify gains of $14.6 million based on market pricing
as
of September 30, 2006 to earnings from the balance in accumulated other
comprehensive income (loss) on the Consolidated Balance Sheet during the
next
twelve months.
At
September 30, 2006, the Company had derivative assets of $25.4 million of which
$1.8 million is included in other assets on the Consolidated Balance Sheet.
The
Company also had derivative liabilities of $8.0 million on the Consolidated
Balance Sheet at September 30, 2006. 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
September 30, 2006. Hedging activities related to cash settlements
on commodities increased revenues by $9.1 million and $19.8 million for the
three and nine months ended September 30, 2006.
Gains
and
losses related to ineffectiveness and derivative instruments not designated
as
hedging instruments are included in other income (expense). There was no
ineffectiveness related to cash-flow hedges recorded for the three and nine
months ended September 30, 2006 or for the three months ended September 30,
2005. There were no gains or losses related to derivative instruments not
designated as hedged instruments for the six months ended June 30, 2005
(Predecessor) as no derivative instruments existed.
The
Company’s accrued liabilities consists of the following:
|
|
September
30, 2006
|
|
December
31, 2005
|
|
|
|
(In
thousands)
|
|
Accrued
capital costs
|
|
$
|
19,201
|
|
$
|
17,607
|
|
Accrued
Calpine settlement |
|
|
11,400 |
|
|
- |
|
Accrued
lease operating expense
|
|
|
7,658
|
|
|
3,202
|
|
Accrued
payroll and employee incentive expense
|
|
|
2,181
|
|
|
2,696
|
|
Other
|
|
|
2,164
|
|
|
4,892
|
|
Total
|
|
$
|
42,604
|
|
$
|
28,397
|
|
|
|
|
|
|
|
|
|
(8)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (“ARO”) is as
follows:
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
(In
thousands)
|
|
ARO
as of January 1, 2006
|
|
$
|
9,467
|
|
Liabilities
incurred during period
|
|
|
115
|
|
Liabilities
settled during period
|
|
|
(15
|
)
|
Accretion
expense
|
|
|
587
|
|
Other
Adjustments
|
|
|
(4
|
)
|
ARO
as of September 30, 2006
|
|
$
|
10,150
|
|
|
|
|
|
|
Of
the
total ARO, approximately $0.5 million is classified as a current liability
at
September 30, 2006.
The
Company’s credit facilities consist of a four-year senior secured revolving line
of credit of up to $400.0 million with a borrowing base of $325.0 million and
a
five-year $75.0 million senior second lien term loan. All
amounts drawn under the revolver are due and payable on July 7, 2009. The
principal balance associated with the senior secured lien term loan is due
and
payable on July 7, 2010.
On
September 30, 2006, the Company had outstanding borrowings and letters of credit
of $240.0 million and $1.0 million, respectively. Net borrowing availability
was
$159.0 million at September 30, 2006.
The
Company was in compliance with all covenants at September 30, 2006.
(10)
|
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 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
Calpine
Corporation and certain of its subsidiaries filed for protection under the
federal bankruptcy laws in the United States Bankruptcy Court of the Southern
District of New York (the “Court”) on December 20, 2005. Calpine Energy
Services, L.P., which filed for bankruptcy, has continued to make the required
deposits into the Company’s margin account and to timely pay for natural gas
production it purchases from the Company’s subsidiaries under various natural
gas supply agreements. As part of the Acquisition, Calpine and the Company
entered into a Transition Services Agreement, pursuant to which both parties
were to provide certain services for the other for various periods of time.
Calpine’s obligation to provide services under the Transition Services Agreement
ceased on July 6, 2006 and certain of Calpine’s services ceased prior to the
conclusion of the contract, which in neither case had any material effect
on the
Company. Additionally, Calpine Producer Services, L.P., which filed for
bankruptcy, generally is performing its obligations under the Marketing and
Services Agreement with the Company.
There
remains the possibility, however, that there will be issues between the Company
and Calpine that could amount to material contingencies in relation to the
Purchase and Sale Agreement and interrelated agreements concurrently executed
therewith, dated July 7, 2005, by and among Calpine, the Company, and various
other signatories thereto (collectively, the “Purchase Agreement”), including
unasserted claims and assessments with respect to (i) the still pending Purchase
Agreement and the amounts that will be payable in connection therewith, (ii)
whether or not Calpine and its affiliated debtors will, in fact, perform their
remaining obligations in connection with the Purchase Agreement; and (iii)
the
ultimate disposition of the remaining Non-Consent Properties (and related
royalty revenues). Calpine has specific obligations to the Company under the
Purchase Agreement relating to these matters, and also has “further assurances”
duties to the Company under the Purchase Agreement.
In
addition, as to certain of the other oil and natural gas properties the Company
purchased from Calpine in the Acquisition and for which payment was made on
July
7, 2005, the Company will seek additional documentation from Calpine to
eliminate any open issues in the Company’s title or resolve any issues as to the
clarity of the Company’s ownership. Requests for additional documentation are
customary in connection with transactions similar to the Acquisition. In the
Acquisition, certain of these properties require ministerial governmental action
approving the Company as qualified assignee and operator, which is typically
required even though in most cases Calpine has already conveyed the properties
to the Company free and clear of mortgages and liens in favor of Calpine’s
creditors. As to certain other properties, the documentation delivered by
Calpine at closing under the Purchase Agreement was incomplete. The Company
remains hopeful that Calpine will continue to work cooperatively with the
Company to secure these ministerial governmental approvals and to accomplish
the
curative corrections for all of these properties. In addition, as to all
properties acquired by the Company in the Acquisition, Calpine contractually
agreed to provide the Company with such further assurances as the Company may
reasonably request. Nevertheless, as a result of Calpine’s bankruptcy filing, it
remains uncertain as to whether Calpine will respond cooperatively. If Calpine
does not fulfill its contractual obligations and does not complete the
documentation necessary to resolve these issues, the Company will pursue all
available remedies, including but not limited to a declaratory judgment to
enforce the Company’s rights and actions to quiet title. After pursuing these
matters, if the Company experiences a loss of ownership with respect to these
properties without receiving adequate consideration for any resulting loss
to
the Company, an outcome the Company’s management considers to be remote, then
the Company could experience losses which could have a material adverse effect
on the Company’s financial condition, statement of operations and cash
flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Court seeking the entry of an order authorizing Calpine to
assume certain oil and natural gas leases Calpine has previously sold or agreed
to sell to the Company in the Acquisition, to the extent those leases constitute
“unexpired leases of non-residential real property” and were not fully
transferred to the Company at the time of Calpine’s filing for bankruptcy.
According to this motion, Calpine filed the motion in order to avoid the
automatic forfeiture of any interest it may have in these leases by operation
of
a statutory deadline. Calpine’s motion did not request that the Court determine
whether these properties belong to the Company or Calpine, but the Company
understands it was meant to allow Calpine to preserve and avoid forfeiture
under
the Bankruptcy Code of whatever interest Calpine may possess, if any, in these
oil and natural gas leases. The Company disputes Calpine’s contention that it
may have an interest in any significant portion of these oil and natural gas
leases and intends to take the necessary steps to protect all of the Company’s
rights and interest in and to the leases. On July 7, 2006, the Company filed
an
objection in response to Calpine’s motion, wherein the Company asserted that oil
and natural gas leases constitute interests in real property that are not
subject to “assumption” under the Bankruptcy Code. In the objection the Company
also requested that (a) the Court eliminate from the order certain Federal
offshore leases from the Calpine motion because these properties were fully
conveyed to the Company in July 2005, and the Minerals Management Service has
subsequently recognized the Company as owner and operator of these properties,
and (b) any order entered by the Court be without prejudice to, and fully
preserve 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
Court to require the parties to promptly address and resolve any remaining
issues under the pre-bankruptcy definitive agreements with Calpine and proposed
to the Court that the parties seek arbitration (or at least mediation) to
complete the following:
|
·
|
Calpine’s
conveyance of the Non-Consent Properties to the
Company;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which the Company
has
already paid Calpine; and
|
|
·
|
Resolution
of the final amounts the Company is to pay Calpine, which the Company
has
concluded is approximately $79 million, consisting of roughly $68
million
for the Non-Consent Properties and approximately $11 million in other
true-up payment obligations.
|
At
a
hearing held on July 12, 2006, the Court in Calpine Corporation’s bankruptcy
took the following steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Minerals Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render the objection
of
the Company inapplicable at that time;
and
|
|
·
|
The
Court also encouraged Calpine and the Company to arrive at a business
solution to all remaining issues including approximately $68 million
payable to Calpine for conveyance of the Non-Consent Properties.
|
On
August
1, 2006, the Company filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts and unliquidated damages in amounts that can
not
presently be determined. The
Company continues to undertake to work with Calpine on a cooperative and
expedited basis toward resolution of unresolved conveyance of properties and
post closing adjustments under the Purchase Agreement.
By
a
proposed stipulation dated October 18, 2006, Calpine and the Department of
Justice agreed to further extend the deadline to assume or reject the MMS Oil
and Gas Leases under Section 365 of the Bankruptcy Code from November 15, 2006
to January 31, 2007, to the extent the MMS Oil and Gas Leases are “unexpired
leases” subject to Section 365. The Company has filed an objection to this
proposed stipulation requesting the Court condition its approval of the proposed
stipulation on inclusion of appropriate language adequately reserving the
Company’s rights with respect to the MMS Oil and Gas Leases and clarifying that
the United States Department of Interior will not take regulatory action with
respect to such leases without first seeking relief from the Court. On November
1, 2006, Calpine and the State of California submitted a similar proposed
stipulation extending the deadline to assume or reject the CSLC Leases until
January 31, 2007. The Company will take all necessary action to ensure its
rights under the CSLC Leases are fully protected.
The
Company continues to believe that it is unlikely that any challenges by the
Calpine debtors or their creditors to the fairness of the Acquisition would
be
successful. However, there can be no assurance that Calpine, its creditors
or
interest holders may not challenge the fairness of some or all of the
Acquisition. For a number of reasons, including the Company’s understanding of
the process that Calpine followed in allowing market forces to set the purchase
price for the Acquisition, the Company believes that it is unlikely that any
challenge to the fairness of the Acquisition would be successful.
Environmental
Environmental
expenditures are expensed or capitalized, as appropriate, depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations, and that do not have future economic benefit, are
expensed. Liabilities related to future costs are recorded on an undiscounted
basis when environmental assessments and/or remediation activities are probable
and the cost can be reasonably estimated. The Company performed an environmental
remediation study for two sites in California and correspondingly, recorded
a
liability, which at September 30, 2006 and December 31, 2005 was $0.1
million and $0.7 million, respectively. The Company does not expect that the
outcome of our environmental matters discussed above will have a material
adverse effect on the Company’s financial position, results of operations or
cash flows.
Participation
in a Regional Carbon Sequestration Partnership
The
Company has made preliminary preparations in connection with its participating
in the United States Department of Energy’s (“DOE”) Regional Carbon
Sequestration Partnership program (“WESTCARB”) with the California Energy
Commission and the University of California, Lawrence Berkeley Laboratory.
The
Company has been selected by the DOE for this project. Under WESTCARB, the
Company would be required to drill a carbon injection well, recondition an
idle
well for use as an observation well and provide WESTCARB with certain
proprietary well data and technical assistance related to the evaluation and
injection of carbon
dioxide
into a suitable natural gas reservoir in the Sacramento Basin. The Company’s
maximum contribution to WESTCARB is $1.0 million and will be limited to 20%
of
the total contributions to the project. The Company will not have any obligation
under the WESTCARB project until it has entered into an acceptable contract
and
the project has obtained proper and necessary local, state and federal
regulatory approvals, land use authorizations and third party property rights.
No accrual was recorded at September 30, 2006 as the study is still in the
preliminary stage.
(11)
|
Comprehensive
Income
|
The
Company’s total comprehensive income (loss) is shown below. For the six months
ended June 30, 2005, the Predecessor did not have transactions affecting
comprehensive income.
|
|
Three
Months Ended
September
30, 2006
|
|
Three
Months Ended
September
30, 2005
|
|
Nine
Months Ended
September
30, 2006
|
|
|
|
(In
thousands)
|
|
Accumulated
other comprehensive loss - beginning of period
|
$
|
(11,852
|
)
|
|
|
|
$
|
-
|
|
|
|
|
$
|
(50,731
|
)
|
Net
income
|
|
|
11,922
|
|
|
|
|
|
8,207
|
|
|
|
|
|
31,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in fair value of derivative hedging instruments
|
|
|
45,638
|
|
|
|
|
|
(109,392
|
)
|
|
|
|
|
119,036
|
|
|
|
|
Hedge
settlements reclassed to income
|
|
|
(9,114
|
)
|
|
|
|
|
2,221
|
|
|
|
|
|
(19,804
|
)
|
|
|
|
Tax
provision related to hedges
|
|
|
(13,880
|
)
|
|
|
|
|
40,725
|
|
|
|
|
|
(37,709
|
)
|
|
|
|
Total
other comprehensive income (loss)
|
|
|
22,644
|
|
|
22,644
|
|
|
(66,446
|
)
|
|
(66,446
|
)
|
|
61,523
|
|
|
61,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income
|
|
|
34,566
|
|
|
|
|
|
(58,239
|
)
|
|
|
|
|
92,935
|
|
|
|
|
Accumulated
other comprehensive income (loss)
|
|
|
|
|
$
|
10,792
|
|
|
|
|
$
|
(66,446
|
)
|
|
|
|
$
|
10,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12)
|
Stock-Based
Compensation
|
Adoption
of SFAS-123R
On
January 1, 2003, Calpine prospectively adopted the fair market value method
of accounting for stock-based employee compensation pursuant to SFAS
No. 123. Expense amounts included in the combined historical financial
statements for the six months ended June 30, 2005 are based on stock based
compensation granted to employees by Calpine. Stock options were granted at
an
option price equal to the quoted market price at the date of the grant or
award.
In
determining the Company’s accounting policies, the Company chose to apply the
intrinsic value method pursuant to APB No. 25, “Stock Issued to Employees”
(“APB No. 25”), effective July 1, 2005. Under APB No. 25, no compensation
expense is recognized when the exercise price for options granted equals the
fair value of the Company’s common stock on the date of the grant. Accordingly,
the provisions of SFAS No. 123 permit the continued use of the method
prescribed by APB No. 25 but require additional disclosures, including pro
forma calculations of net income (loss) per share as if the fair value method
of
accounting prescribed by SFAS No. 123 had been applied.
Following
is a summary of the Company’s net income and net income per share for the three
months ended September 30, 2005 as reported and on a pro forma basis as if
the
fair value method prescribed by SFAS No. 123 had been applied.
|
|
Three
Months Ended September 30, 2005
|
|
|
|
(In
thousands)
|
|
Net
income, as reported
|
|
$
|
8,207
|
|
Deduct:
stock-based employee compensation expense determined under
the
fair value method for all awards, net of related tax
effects
|
|
|
(288
|
)
|
Pro
forma net income
|
|
$
|
7,919
|
|
Net
income per share:
|
|
|
|
|
Basic,
as reported
|
|
$
|
0.16
|
|
Basic,
pro forma
|
|
$
|
0.16
|
|
Diluted,
as reported
|
|
$
|
0.16
|
|
Diluted,
pro forma
|
|
$
|
0.16
|
|
Effective
January 1, 2006, the Company began accounting for stock-based compensation
under
SFAS No. 123R, whereby the Company records stock-based compensation expense
based on the fair value of awards described below. Stock-based compensation
expense recorded for all share-based payment arrangements for the three and
nine
months ended September 30, 2006 (Successor) was $1.0 million and $4.3 million,
with a tax benefit of $0.4 million and $1.6 million, respectively. Stock-based
compensation expense for the three months ended September 30, 2005 (Successor)
was $1.7 million with a tax benefit of $0.7 million. For the six months ended
June 30, 2005 (Predecessor), stock-based compensation expense recorded was
$0.2
million with a tax benefit of $0.1 million. The remaining compensation expense
associated with total unvested awards as of September 30, 2006 was $9.8 million.
Successor
2005
Long-Term Incentive Plan
In
July
2005, the Board of Directors adopted the Rosetta 2005 Long-Term Incentive Plan
whereby stock is granted to employees, officers and directors of the Company.
The Plan allows for the grant of stock options, stock awards, restricted stock,
restricted stock units, stock appreciation rights, performance awards and other
incentive awards. Employees, non-employee directors and other service providers
of the Company and its affiliates who, in the opinion of the Compensation
Committee or another Committee of the Board of Directors (the “Committee”), are
in a position to make a significant contribution to the success of the Company
and the Company’s affiliates are eligible to participate in the Plan. The Plan
provides for administration by the Committee, which determines the type and
size
of award and sets the terms, conditions, restrictions and limitations applicable
to the award within the confines of the Plan’s terms. The maximum number of
shares available for grant under the plan is 3,000,000 shares of common stock
plus any shares of common stock that become available under the Plan for any
reason other than exercise, such as shares traded for the related tax
liabilities of employees. The maximum number of shares of common stock available
for grant of awards under the Plan to any one participant is (i) 300,000
shares during any fiscal year in which the participant begins work for Rosetta
and (ii) 200,000 shares during each fiscal year thereafter.
Stock
Options
The
Company has granted stock options under its 2005 Long-Term Incentive Plan.
Options generally expire ten years from the date of grant. The exercise price
of
the options can not be less than the fair market value per share of the
Company’s common stock on the grant date.
The
weighted average fair value at date of grant for options granted during the
nine
months ended September 30, 2006 was $10.69 per share. The weighted
average fair value at date of grant for options
granted
during the three months ended September 30, 2005 (Successor) was $9.53 per
share
and for the six months ended June 30, 2005 (Predecessor), the weighted average
fair value at date of grant for options granted was $1.27 per share. The fair
value of options granted is estimated on the date of grant using the
Black-Scholes option-pricing model with the following assumptions:
|
|
Successor
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Nine
Months Ended
September
30, 2006
|
|
Three
Months Ended
September
30, 2005
|
|
|
Six
Months Ended
June
30, 2005
|
|
Expected
option term (years)
|
|
|
6.5
|
|
|
6.5
|
|
|
|
2.5
|
|
Expected
volatility
|
|
|
56.65
|
%
|
|
56.65
|
%
|
|
|
58.00
|
%
|
Expected
dividend rate
|
|
|
0.00
|
%
|
|
0.00
|
%
|
|
|
0.00
|
%
|
Risk
free interest rate
|
|
|
4.33%
- 5.15
|
%
|
|
4.03%
- 4.33
|
%
|
|
|
3.62
|
%
|
The
Company has assumed an annual forfeiture rate of 5% for the awards granted
in
2006 based on the Company’s history for this type of award to various employee
groups. Compensation expense is recognized ratably over the requisite service
period and immediately for retirement-eligible employees.
The
following table summarizes information related to outstanding and exercisable
options held by the Company’s employees at September 30, 2006:
|
|
Shares
|
|
Weighted
Average Exercise Price
Per
Share
|
|
Weighted
Average Remaining Contractual Term
(In
years)
|
|
Aggregate
Intrinsic Value
(In
thousands)
|
|
Outstanding
at the December 31, 2005
|
|
|
706,550
|
|
$
|
16.28
|
|
|
|
|
|
|
|
Granted
|
|
|
245,950
|
|
|
17.83
|
|
|
|
|
|
|
|
Exercised
|
|
|
(32,000
|
)
|
|
16.10
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(59,875
|
)
|
|
16.38
|
|
|
|
|
|
|
|
Outstanding
at September 30, 2006
|
|
|
860,625
|
|
$
|
16.73
|
|
|
9.00
|
|
$
|
747
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
Exercisable at September 30, 2006
|
|
|
349,649
|
|
$
|
16.29
|
|
|
8.87
|
|
$
|
393
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based
compensation expense recorded for stock option awards for the three and nine
months ended September 30, 2006 is $0.6 million and $2.1 million, respectively.
There was no stock-based compensation expense for stock option awards for the
three months ended September 30, 2005. Stock-based compensation expense recorded
for stock option awards for the six months ended June 30, 2005 (Predecessor)
is
$0.2 million. Unrecognized expense as of September 30, 2006 for all outstanding
stock options is $5.3 million and will be recognized over a weighted average
period of 1.47 years.
The
total
intrinsic value of options exercised during the nine months ended September
30,
2006 was $0.1 million. For the six months ended June 30, 2005, the Predecessor
did not have any options exercised. The fair value of awards vested for the
nine
months ended September 30, 2006 was $6.3 million.
Restricted
Stock
The
Company has granted stock under its 2005 Long-Term incentive Plan with a maximum
contractual life of three years. The fair value of restricted stock grants
is
based on the value of the Company’s common stock on the date of grant.
Compensation expense is recognized ratably over the requisite service period.
The Company also assumes an annual forfeiture rate of 5 % for these awards
based
on the Company’s history for this type of award to various employee
groups.
The
following table summarizes information concerning restricted stock held by
the
Company’s employees at September 30, 2006:
|
|
Shares
|
|
Weighted
Average Grant Date Fair Value
|
|
Non-vested
shares outstanding at December 31, 2005
|
|
|
581,900
|
|
$
|
16.27
|
|
Granted
|
|
|
129,800
|
|
|
17.70
|
|
Vested
|
|
|
(344,975
|
)
|
|
16.11
|
|
Forfeited
|
|
|
(35,125
|
)
|
|
16.18
|
|
Non-vested
shares outstanding at September 30, 2006
|
|
|
331,600
|
|
$
|
17.00
|
|
|
|
|
|
|
|
|
|
The
non-vested restricted stock outstanding at September 30, 2006 vests at a rate
of
25% on the first anniversary of the date of grant, 25% on the second anniversary
and 50% on the third anniversary. The restrictions on 270,000 shares lapsed
on
the day after the Company’s effective date of its recently completed initial
public offering in February 2006 and therefore vested in the first quarter
of
2006.
Stock-based
compensation expense recorded for restricted stock awards for the three and
nine
months ended September 30, 2006 was $0.4 million and $2.2 million, respectively,
and $1.7 million for the three months ended September 30, 2005. Unrecognized
expense as of September 30, 2006 for all outstanding restricted stock awards
is
$4.5 million and will be recognized over a weighted average period of 1.58
years.
Predecessor
Retirement
Savings Plan
The
Predecessor had a defined contribution savings plan, under Section 401(a)
and 501(a) of the Internal Revenue Code, in which the Predecessor’s employees
were eligible to participate. The plan provided for tax deferred salary
deductions and after-tax employee contributions. Employees were immediately
eligible upon hire. Contributions included employee salary deferral
contributions and employer profit-sharing contributions made entirely in cash
of
4% of employees’ salaries, with employer contributions capped at $8,400 per year
for 2005. There were no employer profit-sharing contributions for the six months
ended June 30, 2005.
2000
Employee Stock Purchase Plan
The
Predecessor adopted the 2000 Employee Stock Purchase Plan (“ESPP”) in May 2000.
The Predecessor’s eligible employees could, in the aggregate, purchase up to
28,000,000 shares of common stock at semi-annual intervals through periodic
payroll deductions. Purchases were limited to either a maximum value of $25,000
per calendar year based on the IRS Code Section 423 limitation or limited
to 2,400 shares per purchase interval. Shares were purchased on May 31 and
November 30 of each year until termination of the plan on May 31,
2010. Under the ESPP, 36,817 shares were issued to Calpine’s employees at a
weighted average fair market value of $2.53 per share, for the six months ended
June 30, 2005. The purchase price was 85% of the lower of (i) the fair
market value of the common stock on the participant’s entry date into the
offering period, or (ii) the fair market value on the semi-annual purchase
date. The purchase price discount was significant enough to cause the ESPP
to be
considered compensatory under SFAS No. 123. As a result, the ESPP was
accounted for as stock-based compensation in accordance with SFAS No. 123
for the six months ended June 30, 2005. For the six months ended June 30, 2005,
compensation expense of $0.2 million was recorded under the ESPP.
1996
Stock Incentive Plan
The
Predecessor adopted the 1996 Stock Incentive Plan (“SIP”) in September 1996 in
which certain of the Company’s employees were eligible to participate. The SIP
succeeded the Predecessor’s previously adopted stock option program. Under the
SIP, the option exercise price generally equaled the stock’s fair market value
on date of grant. The SIP options generally vested ratably over four years
and
expired after 10 years. As of June 30, 2005, the amount of shares outstanding
under the 1996 incentive plan were 754,284.
Basic
earnings per share is computed by dividing income available to common
stockholders by the weighted average number of shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if
contracts to issue common stock and related stock options were exercised at
the
end of the period.
The
following is a calculation of basic and diluted weighted average shares
outstanding:
|
|
Successor
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended September 30
|
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
Basic
weighted average number of shares outstanding
|
|
|
50,282
|
|
|
50,000
|
|
|
50,211
|
|
|
|
50,000
|
|
Dilution
effect of stock option and awards at the end of
the
period
|
|
|
144
|
|
|
160
|
|
|
173
|
|
|
|
160
|
|
Diluted
weighted average number of shares outstanding
|
|
|
50,426
|
|
|
50,160
|
|
|
50,384
|
|
|
|
50,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
awards and shares excluded from diluted earnings
per
share due to anti-dilutive effect
|
|
|
179
|
|
|
-
|
|
|
229
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Company has one reportable segment, oil and natural gas exploration and
production, as determined in accordance with SFAS No. 131, “Disclosure
About Segments of an Enterprise and Related Information”. See below for
information by geographic location.
Geographic
Area Information
The
Company owns oil and natural gas interests in eight main geographic areas all
within in the United States. Geographic revenue and property, plant and
equipment information below for the three and nine months ended September 30,
2006, the three months ended September 30, 2005 and the six months ended June
30, 2005 are based on physical location of the assets at the end of each period.
|
|
Successor
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended September 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2006
(1)
|
|
2005
(1)
|
|
2006
(1)
|
|
|
2005
|
|
Oil
and Natural Gas Revenue
|
|
(In thousands)
|
|
|
|
California
|
|
$
|
18,820
|
|
$
|
20,893
|
|
$
|
54,921
|
|
|
$
|
43,385
|
|
Lobo
|
|
|
21,009
|
|
|
18,888
|
|
|
50,090
|
|
|
|
26,474
|
|
Perdido
|
|
|
4,939
|
|
|
5,712
|
|
|
21,722
|
|
|
|
12,380
|
|
State
Waters
|
|
|
1,750
|
|
|
2,964
|
|
|
7,039
|
|
|
|
2,345
|
|
Other
Onshore
|
|
|
8,205
|
|
|
4,267
|
|
|
20,381
|
|
|
|
7,662
|
|
Gulf
of Mexico
|
|
|
6,172
|
|
|
6,463
|
|
|
22,093
|
|
|
|
10,542
|
|
Rockies
|
|
|
591
|
|
|
126
|
|
|
1,555
|
|
|
|
161
|
|
Mid-Continent
|
|
|
596
|
|
|
767
|
|
|
1,506
|
|
|
|
842
|
|
Other
|
|
|
1
|
|
|
6
|
|
|
11
|
|
|
|
40
|
|
|
|
$
|
62,083
|
|
$
|
60,086
|
|
$
|
179,318
|
|
|
$
|
103,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Excludes
the effects of hedging.
|
|
|
Successor
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
Oil
and Natural Gas Properties (2)
|
|
(In
thousands)
|
California
|
|
$
|
430,819
|
|
$
|
386,513
|
|
Lobo
|
|
|
398,754
|
|
|
368,276
|
|
Perdido
|
|
|
43,890
|
|
|
25,983
|
|
State
Waters
|
|
|
21,894
|
|
|
12,067
|
|
Other
Onshore
|
|
|
100,308
|
|
|
75,737
|
|
Gulf
of Mexico
|
|
|
95,375
|
|
|
77,416
|
|
Rockies
|
|
|
35,038
|
|
|
21,224
|
|
Mid-Continent
|
|
|
8,676
|
|
|
5,969
|
|
Other
|
|
|
3,868
|
|
|
2,912
|
|
|
|
$
|
1,138,622
|
|
$
|
976,097
|
|
|
|
|
|
|
|
|
|
|
(2)
|
Oil
and natural gas properties at September 30, 2006 and December 31,
2005 are
reported gross. Under the full cost method of accounting for oil
and
natural gas properties, depreciation, depletion and amortization
is not
allocated to properties.
|
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
Various
statements, other than statements of historical fact, included in this report,
are forward-looking statements. In some cases, you can identify a
forward-looking statement by terminology such as “may”, “could”, “should”,
“expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”,
“predict”, “potential”, “pursue”, “target” or “continue”, the negative of such
terms or other comparable terminology.
The
forward-looking statements contained in this report are largely based on our
expectations, which reflect estimates and assumptions made by our management.
These estimates and assumptions reflect our best judgment based on currently
known market conditions and other factors. Although we believe such estimates
and assumptions to be reasonable, they are inherently uncertain and involve
a
number of risks and uncertainties that are beyond our control. Management’s
assumptions about future events may prove to be inaccurate. For a more detailed
description of the risks and uncertainties, see Item 1A. Risk Factors in our
annual report on Form 10-K for the year ended December 31, 2005 and Item 1A.
Risk Factors in this report. We do not intend to publicly update or revise
any
forward-looking statements as a result of new information, future events or
otherwise. These cautionary statements qualify all forward-looking statements
attributable to us, or persons acting on our behalf. Management cautions all
readers that the forward-looking statements contained in this report are not
guarantees of future performance, and we cannot assure any reader that such
statements will be realized or the forward-looking events and circumstances
will
occur. Actual results may differ materially from those anticipated or implied
in
the forward-looking statements due to various factors, including:
·
|
The
timing and extent of changes in commodity prices, particularly natural
gas;
|
·
|
Various
drilling and exploration risks that may delay or prevent commercial
operation of new wells;
|
·
|
Economic
slowdowns that can adversely affect consumption of oil and natural
gas by
businesses and consumers;
|
·
|
Resources
expended in connection with Calpine’s bankruptcy including our increased
costs for lawyers, consultant experts and related expenses, as well
as the
lost opportunity costs associated with our internal resources dedicated
to
these matters;
|
·
|
Uncertainties
that actual costs may be higher than estimated;
|
·
|
Factors
that impact the exploration of oil or natural gas resources, such
as the
geology of a resource, the total amount and costs to develop recoverable
reserves, and legal title, regulatory, natural gas administration,
marketing and operational factors relating to the extraction of oil
and
natural gas;
|
·
|
Uncertainties
associated with estimates of oil and natural gas reserves;
|
·
|
Our
ability to access the capital markets on attractive terms or at
all;
|
·
|
Refusal
by or inability of our current or potential counterparties or vendors
to
enter into transactions with us or fulfill their obligations to us;
|
·
|
Our
inability to obtain credit or capital in desired amounts or on favorable
terms;
|
·
|
Present
and possible future claims, litigation and enforcement actions;
|
·
|
Effects
of the application of regulations, including changes in regulations
or the
interpretation thereof;
|
·
|
Availability
of processing and transportation;
|
·
|
Potential
for disputes with mineral lease and royalty owners regarding calculation
and payment of royalties, including basis of pricing, adjustment
for
quality, measurement and allowable costs and expenses;
|
·
|
Developments
in oil-producing and natural gas-producing countries;
|
·
|
Competition
in the oil and natural gas industry; and
|
·
|
Adverse
weather conditions, hurricanes, tropical storms, earthquakes, mud
slides,
flooding and other natural disasters which may occur in areas of
the
United States in which we have operations, including the Federal
waters of
the Gulf of Mexico, as well as new energy package insurance coverage
limitations related to any single named windstorm; and uncertainty
with
respect to potential environmental, health and safety
liabilities.
|
ITEM
2. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
Overview
Rosetta
Resources Inc. is an independent oil and natural gas company engaged in the
acquisition, exploration, development and production of oil and natural gas
properties in the United States. We were formed as a Delaware corporation in
June 2005. In July 2005, we acquired the domestic oil and natural gas business
of Calpine Corporation and its affiliates. Our main operations are concentrated
in the Sacramento Basin of California, the Lobo and Perdido Trends in South
Texas, the Gulf of Mexico and the Rocky Mountains.
In
this
section, we sometimes refer to Rosetta as “Successor”, and we sometimes refer to
Calpine Corporation and its affiliates, from whom we acquired our initial
domestic oil and natural gas business and associated oil and natural gas
properties as “Predecessor”. Additionally, we sometimes refer to our acquisition
of Calpine’s domestic oil and natural gas business as the
“Acquisition”.
In
the
first nine months of 2006, relatively high oil and natural gas prices have
led
to higher demand for drilling rigs, operating personnel and field supplies
and
services, and have caused increases in the costs of those goods and services.
Given the inherent volatility of oil and natural gas prices that are influenced
by many factors beyond our control, we plan our activities and budget based
on
conservative sales price assumptions. We focus our efforts on increasing natural
gas reserves and production while controlling costs at a level that is
appropriate for long-term operations. Our future earnings and cash flows are
dependent on our ability to manage our overall cost structure to a level that
allows for profitable production. Our future earnings will also be impacted
by
the changes in fair market value of hedges we executed to mitigate the
volatility in the changes of oil and natural gas prices in future periods when
such positions are settled as these instruments meet the criteria to be
accounted for as cash flow hedges. Until settlement, the changes in fair market
value of our hedges will be included as a component of stockholder’s equity to
the extent effective. In periods of rising prices, these transactions will
mitigate future earnings and in periods of declining prices will increase future
earnings in the respective period the positions are settled.
Like
all
oil and natural gas exploration and production companies, we face the challenge
of natural production declines. As initial reservoir pressures are depleted,
oil
and natural gas production from a given well naturally decreases. Thus, an
oil
and natural gas exploration and production company depletes part of its asset
base with each unit of oil or natural gas it produces. We attempt to overcome
this natural decline by drilling and acquiring more reserves than we produce.
Our future growth will depend on our ability to continue to add reserves in
excess of production. We will maintain our focus on costs to add reserves
through drilling and acquisitions as well as the costs necessary to produce
our
reserves. Our ability to add reserves through drilling is dependent on our
capital resources and can be limited by many factors, including our ability
to
timely obtain drilling permits and regulatory approvals. The permitting and
approval process has been more difficult in recent years than in the past due
to
increased activism from environmental and other groups and has extended the
time
it takes us to receive permits. We can be disproportionately disadvantaged
by
delays in obtaining or failing to obtain drilling approvals compared to
companies with larger or more dispersed property bases. As a result, we are
less
able to shift drilling activities to areas where permitting may be easier and
we
have fewer properties over which to spread the costs related to complying with
these regulations and the costs of foregone opportunities resulting from
delays.
Financial
Highlights
For
the
nine month period ended September 30, 2006, we produced 24.4 Bcfe with average
revenue of $8.16 per Mcfe. Our natural gas production for the nine months ended
September 30, 2006 was 21.9 Bcf and our oil production for the same period
was
414.3 MBbls. Our average natural gas prices were $7.84 per Mcf, including the
effects of hedging, and average oil prices for the same period were $65.99
per
Bbl. For the nine months ended September 30, 2006, we had revenues of $199.1
million including the effects of hedging with net income of $31.4 million and
diluted earnings per share of $0.62.
Calpine
Bankruptcy
On
December 20, 2005, Calpine and certain of its subsidiaries, including Calpine
Fuels, filed for protection under federal bankruptcy laws in the United States
Bankruptcy Court of the Southern District of New York (“the Court”). The filing
raises certain concerns regarding aspects of our relationship with Calpine
which
we will closely monitor as the Calpine bankruptcy proceeds. The following are
our principal areas of concern:
|
·
|
Calpine,
its creditors or interest holders may challenge the fairness of some
or
all of the Acquisition. For a number of reasons, including our
understanding of the process which Calpine followed in allowing market
forces to set the purchase price for the Acquisition, we believe
that it
is unlikely that any challenge to the fairness of the Acquisition
would be
successful;
|
|
·
|
The
bankruptcy proceeding may prevent, frustrate or delay our ability
to
receive record legal title to certain properties originally listed
as
determined to be Non-Consent Properties which we are entitled to
obtain
under the Purchase Agreement;
|
|
·
|
Additionally,
the bankruptcy proceeding may prevent, frustrate or delay our ability
to
receive corrective documentation from Calpine for certain properties
that
we bought from Calpine and paid for, in cases where Calpine delivered
incomplete documentation, including documentation related to certain
ministerial governmental approvals;
and
|
·
Calpine
may stop purchasing gas from us under our gas purchase contracts with Calpine.
Since the date of the bankruptcy filing, Calpine has continued buying natural
gas from us and making timely payments. Calpine has sought and obtained
bankruptcy court approval to continue payments to us for our delivery of natural
gas under our gas purchase and sale contracts with Calpine. Under the terms
of
these contracts, in the event of Calpine’s default in making timely payments, we
are entitled to suspend deliveries to Calpine and instead sell this gas to
third
parties at comparable prices and terms until Calpine cures any such default
(Calpine having 60 days after notice to do so). In terms of the likely impact
of
Calpine’s default under these contracts, should this ever occur, we expect to be
able to minimize our exposure for Calpine’s non-payment to four days of sales
under these contracts, or approximately $1.5 million in lost sales at production
rates and prices as of September 30, 2006.
Transfers
Pending at Calpine’s Bankruptcy
At
the
closing of the Acquisition on July 7, 2005, we retained approximately $75
million of the purchase price in respect to Non-Consent Properties identified
by
Calpine as requiring third party consents or waivers of preferential rights
to
purchase that were not received before closing. Those Non-Consent Properties
were not included in conveyances delivered at the closing. Subsequent analysis
determined that a portion of the Non-Consent Properties, with an approximate
allocation value of $29 million under the Purchase Agreement did not require
consents or waivers. For that portion of the Non-Consent Properties for which
third party consents were in fact required (having an approximate value of
$39
million under the Purchase Agreement) and for which we obtained the required
consents or waivers, as well as for all Non-Consent Properties that did not
require consents or waivers, we believe that Calpine was and is obligated to
have transferred to us the record title, free of any mortgages and other liens.
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 a third party’s
preferential right to purchase, and, in addition, a post-closing adjustment
is
required to credit Rosetta for approximately $0.3 million for a property which
was transferred to us but 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 a third party’s
preferential right to purchase) were satisfied earlier, and certainly no later
than December 15, 2005, when we tendered once again the amounts necessary to
conclude the settlement of the Non-Consent Properties.
We
believe we are the equitable owner of each of the Non-Consent Properties for
which Calpine was and is obligated to have transferred to us 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 and further assurances required to eliminate any
open issues on title to the remaining properties discussed below, we are
prepared to pay Calpine approximately $68 million, subject to appropriate
adjustment for the associated net revenues and expenses through December 15,
2005. Our statement of operations for the nine months ended September 30, 2006
does not include any net revenues or production from any of the Non-Consent
Properties.
If
Calpine does not provide us with record title, free of any mortgages for all
of
these properties and other liens, to any of the Non-Consent Properties
(excluding that portion of these properties subject to a third party’s
preferential right to purchase), we will have a total of approximately $68
million available to us for general corporate purposes, including for the
purpose of acquiring additional properties. We also have approximately $7.1
million, previously withheld for that portion of the Non-Consent Properties
subject to a third party’s preferential right to purchase, which will also be
available to us for general corporate purposes, including for the purpose of
acquiring additional properties.
In
addition, as to certain of the other oil and natural gas properties we purchased
from Calpine in the Acquisition and for which payment was made on July 7, 2005,
we will seek additional documentation from Calpine to eliminate any open issues
in our title or resolve any issues as to the clarity of our ownership. Requests
for additional documentation are customary in connection with transactions
similar to the Acquisition. In the Acquisition, certain of these properties
require ministerial governmental action approving us as qualified assignee
and
operator, which is typically required even though in most cases Calpine has
already conveyed
the
properties to us free and clear of mortgages and liens in favor of Calpine’s
creditors. As to certain other properties, the documentation delivered by
Calpine at closing under the Purchase Agreement was incomplete. We remain
hopeful that Calpine will continue to work cooperatively with us to secure
these
ministerial governmental approvals and to accomplish the curative corrections
for all of these properties. In addition, as to all properties acquired by
us in
the Acquisition, Calpine contractually agreed to provide us with such further
assurances as we may reasonably request. Nevertheless, as a result of Calpine’s
bankruptcy filing, it remains uncertain as to whether Calpine will respond
cooperatively. If Calpine does not fulfill its contractual obligations and
does
not complete the documentation necessary to resolve these issues, we will pursue
all available remedies, including but not limited to a declaratory judgment
to
enforce our rights and actions to quiet title. After pursuing these matters,
if
we experience a loss of ownership with respect to these properties without
receiving adequate consideration for any resulting loss to us, an outcome we
consider to be remote, then we could experience losses which could have a
material adverse effect on our financial condition, statement of operations
and
cash flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Court seeking the entry of an order authorizing Calpine to
assume certain oil and natural gas leases Calpine has previously sold or agreed
to sell to us in the Acquisition, to the extent those leases constitute
“unexpired leases of non-residential real property” and were not fully
transferred to us at the time of Calpine’s filing for bankruptcy. According to
this motion, Calpine filed the motion in order to avoid the automatic forfeiture
of any interest it may have in these leases by operation of a statutory
deadline. Calpine’s motion did not request that the Court determine whether
these properties belong to us or Calpine, but we understand it was meant to
allow Calpine to preserve and avoid forfeiture under the Bankruptcy Code of
whatever interest Calpine may possess, if any, in these oil and natural gas
leases. We dispute Calpine’s contention that it may have an interest in any
significant portion of these oil and natural gas leases and intend to take
the
necessary steps to protect all of our rights and interest in and to the leases.
On July 7, 2006, we filed an objection in response to Calpine’s motion, wherein
we asserted that oil and natural gas leases constitute interests in real
property that are not subject to “assumption” under the Bankruptcy Code. The
objection also requested that (a) the Court eliminate from the order certain
Federal offshore leases from the Calpine motion because these properties were
fully conveyed to us in July 2005, and the Minerals Management Service has
subsequently recognized us as owner and operator of these properties and (b)
any
order entered by the Court be without prejudice to, and fully preserve our
rights, claims and legal arguments regarding the characterization and ultimate
disposition of the remaining described oil and natural gas properties. In our
objection, we also urged the Court to require the parties to promptly address
and resolve any remaining issues under the pre-bankruptcy Purchase Agreement
with Calpine and proposed to the Court that the parties seek arbitration (or
at
least mediation) to complete the following:
|
·
|
Calpine’s
conveyance of the Non-Consent Properties to
us;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which we have already
paid Calpine; and
|
|
·
|
Resolution
of the final amounts we are to pay Calpine, which we have concluded
is
approximately $79 million, consisting of roughly $68 million for
the
Non-Consent Properties and approximately $11 million in other true-up
payment obligations.
|
At
a
hearing held on July 12, 2006, the Court in Calpine Corporation’s bankruptcy
took the following steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Minerals Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render our objection
inapplicable at that time; and
|
|
·
|
The
Court also encouraged Calpine and us to arrive at a business solution
to
all remaining issues including approximately $68 million payable
to
Calpine for conveyance of the Non-Consent Properties.
|
On
August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts and unliquidated damages in amounts that can
not
presently be determined.
By
a
proposed
stipulation dated October 18, 2006, Calpine and the Department of Justice agreed
to further extend the deadline to assume or reject the MMS Oil and Gas Leases
under Section 365 of the Bankruptcy Code from November 15, 2006 to January
31,
2007, to the extent the MMS Oil and Gas Leases are “unexpired leases” subject to
Section 365. We have filed an objection to this proposed stipulation requesting
the Court condition its approval of the proposed stipulation on inclusion of
appropriate language adequately reserving our rights with respect to the MMS
Oil
and Gas Leases and clarifying that the United States Department of Interior
will
not take regulatory action with respect to such leases without first seeking
relief from the Court. On November 1, 2006, Calpine and the State of California
submitted a similar proposed stipulation extending the deadline to assume or
reject the CSLC Leases until January 31, 2007. We will take all necessary action
to ensure our rights under the CSLC Leases are fully protected.
We
continue to undertake to work with Calpine on a cooperative and expedited basis
toward resolution of unresolved conveyance of properties and post closing
adjustments under the Purchase Agreement.
Critical
Accounting Policies and Estimates
In
our
Annual Report on Form 10-K for the year ended December 31, 2005, we identified
our most critical accounting policies upon which our financial condition depends
as those relating to oil and natural gas reserves, full cost method of
accounting, derivative transactions and hedging activities, asset retirement
obligations, income taxes and stock-based compensation.
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
September 30, 2006 which were based on a Henry Hub gas price of $4.18 per MMBtu
and a West Texas Intermediate oil price of $62.91 per barrel. The use of these
prices resulted in a writedown of $182.1 million at September 30, 2006. Cash
flow hedges of natural gas production in place at September 30, 2006 increased
the calculated ceiling value by approximately $92.2 million (net of tax).
However, subsequent to September 30, 2006 the market price for Henry Hub
increased to $7.42 per MMBtu and the price for West Texas Intermediate decreased
to $58.07 per barrel, and utilizing these prices, our net capitalized costs
of
oil and gas properties exceeded the ceiling amount. As a result no writedown
was
recorded for the quarter ended September 30, 2006. The ceiling value calculated
using subsequent prices includes approximately $17.9 million related to the
positive effects of future cash flow hedges of natural gas production. Due
to
the volatility of commodity prices, should natural gas and oil prices decline
in
the future, it is possible that a writedown could occur.
On
January 1, 2006, we adopted the accounting policies described in Statement
of
Financial Accounting Standards (SFAS) No. 123 (revised 2004) “Share-Based
Payments” (“SFAS No. 123R”). This statement applies to all awards granted,
modified, repurchased or cancelled after January 1, 2006 and to the unvested
portion of all awards granted prior to that date. We adopted this statement
using the modified version of the prospective application (modified prospective
application). Under this method, no prior year amounts have been restated.
Prior
to January 1, 2006, we accounted for stock-based compensation in accordance
with
the intrinsic value based method prescribed by the Accounting Principles Board
Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees”.
With
the
adoption of SFAS No.123R, one of the differences in our method of accounting
is
that unvested stock options are now expensed as a component of stock-based
compensation recorded in General and Administrative Costs in the
Consolidated/Combined Statement of Operations. This expense is based on the
fair
value of the award at the original grant date and is recognized over the
remaining vesting period. Prior to the adoption of SFAS No. 123R, this amount
was included as a pro forma disclosure in the Notes to the Consolidated
Financial Statements. Compensation expense for the three and nine months ended
September 30, 2006 (Successor) was $1.0 million and $4.3 million,
respectively.
In
addition, the application of the forfeiture rate in calculating the fair value
has changed with the adoption of SFAS No.123R. We are now required to estimate
forfeitures on all equity-based compensation and adjust period expenses instead
of recording the actual forfeitures as they occur. Furthermore, we are required
to immediately expense certain awards to retirement eligible employees depending
on the structure of each individual plan. The retirement eligibility provision
only applies to new grants that were awarded after January 1, 2006.
Results
of Operations
For
the
three months ended September 30, 2006, the results of operations have been
compared to the amounts reported for the three months ended September 30, 2005.
However, as we acquired the domestic oil and natural gas business of Calpine
Corporation
and
affiliates in July 2005, the year-to-date results for the period ended September
30, 2006 and 2005 are not comparable and are noted as Successor for the three
months ended September 30, 2005 and Predecessor for the six months ended June
30, 2005. These two year-to-date periods have not been compared because of
differences in accounting principles, primarily the full cost method of
accounting for oil and natural gas properties adopted by us and the successful
efforts method of accounting for oil and natural gas properties followed by
Calpine. In addition, Calpine adopted on January 1, 2003, SFAS No. 123,
“Accounting for Stock-Based Compensation” to measure the cost of employee
services received in exchange for an award of equity instruments, whereas we
adopted the intrinsic value method of accounting for stock options and stock
awards effective July 1, 2005, and as required, have adopted the guidance
for stock-based compensation under SFAS No. 123R effective January 1, 2006.
We believe comparative results for the nine months ended September 30, 2006
and
2005 would be misleading and, therefore, have chosen to present the periods
separately.
Successor
Revenues. Our
revenues are derived from the sale of our oil and natural gas production, which
includes the effects of qualifying hedge contracts. Total revenue of $71.2
million for the third quarter consists primarily of natural gas sales comprising
86% of total revenue on total volumes of 8.7 Bcfe. For the nine months ended
September 30, 2006, natural gas sales also comprised 86% of total revenue on
total volumes of 24.4 Bcfe.
|
|
Successor-Consolidated
|
|
Successor-Consolidated
|
|
|
Predecessor-Combined
|
|
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
|
Total
revenues
|
|
$
|
71,197
|
|
$
|
57,865
|
|
$
|
199,122
|
|
|
$
|
103,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
7.9
|
|
|
6.4
|
|
|
21.9
|
|
|
|
14.5
|
|
Oil
(MBbls)
|
|
|
143.5
|
|
|
103.0
|
|
|
414.3
|
|
|
|
163.8
|
|
Total
Equivalents (Bcfe)
|
|
|
8.7
|
|
|
7.1
|
|
|
24.4
|
|
|
|
15.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$
|
7.77
|
|
$
|
8.03
|
|
$
|
7.84
|
|
|
$
|
6.59
|
|
Avg.
Gas Price per Mcf excluding Hedging
|
|
|
6.61
|
|
|
8.38
|
|
|
6.94
|
|
|
|
-
|
|
Avg.
Oil Price per Bbl
|
|
|
68.51
|
|
|
60.03
|
|
|
65.99
|
|
|
|
49.86
|
|
Avg.
Revenue per Mcfe
|
|
$
|
8.18
|
|
$
|
8.20
|
|
$
|
8.16
|
|
|
$
|
6.70
|
|
Natural
Gas.
Natural
gas sales revenue increased by $9.7 million, including the realized impact
of
derivative instruments, for the three months ended September 30, 2006 as
compared to the three months ended September 30, 2005. The increase is due
to a
gain on derivative instruments of $11.4 million offset by a decrease in natural
gas sales of $1.7 million. The decrease in natural gas sales revenue is due
to a
21% decrease in natural gas prices offset by an increase in gas production
volumes. The largest increase in production volumes were in the Lobo, Other
Onshore, and Perdido regions due to successful well completions. The average
natural gas price decreased from $8.03 per Mcfe to $7.77 per Mcfe, including
the
effects of hedging, for the three months ended September 30, 2006 as compared
to
the three months ended September 30, 2005.
Natural
gas sales revenue was $171.8 million for the nine months ended September 30,
2006, including the effects of hedging, based on total gas production volumes
of
21.9 Bcf. Approximately 80% of the production volumes were from the following
three areas: California, Lobo and Perdido. Average natural gas prices were
$7.84
per Mcf for the respective period. The effect of hedging on natural gas sales
revenue was an increase of $19.8 million for an increase in total price from
$6.94 to $7.84 per Mcf.
Natural
gas sales revenue was $95.6 million with natural gas production volumes of
14.5
Bcf for the six months ended June 30, 2005. The production volumes were
primarily from the Sacramento Basin with 6.5 Bcf or 44.8% and Lobo and Perdido
with a combined production of 5.5 Bcf or 37.9%. Production volumes were lower
than expected due to capital expenditure constraints resulting in reduced
drilling activity. The average price for natural gas was $6.59 per Mcf. There
was no hedging activity for the six months ended June 30, 2005.
Crude
Oil.
Oil
sales revenue increased by $3.6 million for the three months ended September
30,
2006 as compared to the three months ended September 30, 2005. The increase
is
due to a 39% increase in oil production volumes with a 14% increase in oil
prices. Total oil production volumes increased from 103.0 MBbls for the three
months ended 2005 to 143.5 MBbls for the three months
ended
September 30, 2006, primarily due to increases in the Offshore and Other Onshore
regions. The average oil price increased to $68.51 for the three months ended
September 30, 2006 from $60.03 for the comparable period in the prior
year.
Oil
sales
revenue was $27.3 million for the nine months ended September 30, 2006 with
oil
production volumes of 414.3 MBbls. The oil production volumes were primarily
in
the Offshore and Other Onshore regions with approximately 77% of the total
production volumes. The average oil price was $65.99 per Bbl for the nine months
ended September 30, 2006.
For
the
six months ended June 30, 2005, crude oil sales revenue was $8.2 million
based
on production volumes of 163.8 MBbls. Production volumes were primarily from
the
Gulf of Mexico region which produced 72.7 MBbls or 44% of the total oil
production. The average price of oil was $49.86 per Bbl for the six months
ended
June 30, 2005.
The
following table presents information about our operating expenses for the three
and nine months ended September 30, 2006.
|
|
Successor-Consolidated
|
|
Successor-Consolidated
|
|
|
Predecessor-Combined
|
|
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
|
Lease
operating expense
|
|
$
|
9,449
|
|
$
|
8,849
|
|
$
|
27,330
|
|
|
$
|
16,629
|
|
Depreciation,
depletion and amortization
|
|
|
27,906
|
|
|
21,720
|
|
|
77,574
|
|
|
|
30,679
|
|
General
and administrative costs
|
|
$
|
8,316
|
|
$
|
6,880
|
|
$
|
24,645
|
|
|
$
|
9,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$
|
1.09
|
|
$
|
1.25
|
|
$
|
1.12
|
|
|
$
|
1.08
|
|
Avg.
DD&A per Mcfe
|
|
|
3.21
|
|
|
3.08
|
|
|
3.18
|
|
|
|
1.98
|
|
Avg.
G&A per Mcfe
|
|
$
|
0.96
|
|
$
|
0.83
|
|
$
|
1.01
|
|
|
$
|
0.63
|
|
Our
operating expenses for the three and nine months ended September 30, 2006 are
primarily related to the following items:
|
·
|
Lease
Operating Expense.
Lease operating expense increased $0.6 million from the three months
ended
September 30, 2005 to the three months ended September 30, 2006.
The
overall increase is due to an increase in lease expense and ad valorem
tax
of $2.3 million offset by a decrease in work over expense of $1.7
million
primarily due to insurance reimbursement for claims submitted as
a result
of Hurricane Rita. The average lease operating expense decreased
to $1.09
per Mcfe for the three months ended September 30, 2006 from $1.25
per Mcfe
for the comparable period in the prior year.
|
Lease
operating expense of $27.3 million related directly to oil and natural gas
volumes which totaled 24.4 Bcfe for the nine months ended September 30, 2006
or
costs of $1.12 per Mcfe. Lease operating costs were affected by wells that
came
on-line in South Texas.
For
the
six months ended June 30, 2005, lease operating expense was $16.6 million
related to total oil and gas volumes of 15.5 Bcfe or $1.08 per Mcfe. The costs
include work over cost of $0.22 per Mcfe, ad valorem taxes of $0.22 per Mcfe
and
insurance of $0.06 per Mcfe.
|
·
|
Depreciation,
Depletion, and Amortization.
Depreciation, depletion, and amortization expense increased by $6.2
million from the three months ended September 30, 2005 as compared
to the
three months ended September 30, 2006 due to increased production
volumes
and a higher rate. The depletion rate increased from $2.97 per Mcfe
to
$3.13 per Mcfe.
|
Depreciation,
depletion, and amortization expense was $77.6 million for the nine months ended
September 30, 2006 under the full cost method of accounting for oil and natural
gas properties.
For
the
six months ended June 30, 2005, depreciation, depletion, and amortization
expense was $30.7 million. The predecessor used the successful efforts method
of
accounting for oil and natural gas properties. The depletion rate was $1.97 per
Mcfe for the six months ended June 30, 2005.
|
·
|
General
and Administrative Costs.
General and administrative costs for the three months ended September
30,
2006
|
were $8.3 million compared to $6.9 million for the same period in 2005, which
represents a 21% increase over the prior year. The increase was due to an
increase in outside legal and consulting fees relating to the Calpine bankruptcy
and increased Sarbanes Oxley costs due to the hiring of a consulting firm to
assist with the Sarbanes Oxley implementation.
For
the
nine months ended September 30, 2006, general and administrative costs were
$24.6 million, net of capitalization of certain general and administrative
costs
of $2.6 million under the full cost method of accounting for oil and natural
gas
properties. General and administrative costs include salary and employee
benefits as well as legal, consulting, and auditing fees. In addition, stock
compensation expense for the nine months ended September 30, 2006 was $4.3
million and is included in general and administrative costs.
General
and administrative costs for the six months ended June 30, 2005 were $9.7
million, which is net of capitalized general and administrative costs of $3.6
million. General and administrative costs are comprised of items such as
salaries and employee benefits, legal fees, and contract fees. For the six
months ended June 30, 2005, of the $9.7 million in total general and
administrative costs, $5.9 million relates to salary and employee benefits.
In
addition, $1.3 million are legal costs and $1.7 million are merger and
acquisition costs, which relate to the sale of the oil and natural gas business
to the Company.
Total
Other expense.
Other
expense decreased from the third quarter in 2005 to the third quarter in 2006
by
$0.1 million due to a litigation accrual that was settled in the third quarter
of 2006.
For
the
nine months ended September 30, 2006, other expense was $9.7 million composed
of
interest expense of $13.1 million offset by interest income of $3.4 million.
The
interest expense is associated with the senior secured revolving line of credit
and second lien term loan and interest income is related to the interest earned
on the overnight investments of our cash balances.
For
the
six months ended June 30, 2005, other expense of $7.0 million was associated
with the intercompany debt with Calpine Corporation.
Provision
for Income Taxes.
The
effective tax rate for the three and nine months ended September 30, 2006 was
38.0%. The provision for income taxes differs from the tax computed at the
federal statutory income tax rate primarily due to state taxes, tax credits
and
other permanent differences. The effective tax rate for six months ended June
30, 2005 was 38.1%.
Liquidity
and Capital Resources
Our
cash
flows depend on many factors, including the price of oil and natural gas and
the
success of our development and exploration activities as well as future
acquisitions. We actively manage our exposure to commodity price fluctuations
by
executing derivative transactions to hedge the change in prices of our
production thereby mitigating our exposure to price declines, but these
transactions will also limit our earnings potential in periods of rising natural
gas prices. This derivative transaction activity will allow us the flexibility
to continue to execute our capital plan if prices decline during the period
our
derivative transactions are in place. In addition, the majority of our capital
expenditures will be discretionary and could be curtailed if our cash flows
decline from expected levels. In connection with entering into our credit
facilities in July 2005, we entered into a series of natural gas fixed-price
swaps for a significant portion of our expected production through 2009. In
addition, in the third quarter of 2006, we entered into two additional
fixed-price swaps for a total of 9,041 MMBtu per day for 2007 and 2008.
Consistent with our hedge policy, in December 2005, we entered into two
costless collar transactions, which are intended to establish a floor price
and
ceiling price for approximately 10,000 MMBtu per day which represents
approximately 10% of our 2006 natural gas production based on a third party
reserve report at December 31, 2005. In the third quarter of 2006, we also
entered into two additional costless collar transactions for a total of 10,000
MMBtu per day for 2007. The effects of these derivative transactions on our
financial statements are discussed above under “Results of Operations - Natural
Gas”. Additionally, we may enter into other agreements including fixed-price,
forward price, physical purchase and sales contracts, futures, financial swaps,
option contracts and put options.
Senior Secured
Revolving Line of Credit.
BNP
Paribas, in July 2005 provided us with a senior secured revolving line of
credit concurrent with the acquisition in the amount of up to $400.0 million.
This revolving line of credit was syndicated to a group of lenders on
September 27, 2005. Availability under the revolver is restricted to the
borrowing base, which initially was $275.0 million and was reset to $325.0
million, upon amendment, as a result of the hedges put in place in
July 2005 and the favorable effects of the exercise of the over-allotment
option we granted in our private equity offering in July 2005 through which
we
received $70.0 million of funds (net of transaction fees). In July 2005, we
repaid $60.0 million of the $225.0 million in original borrowings on the
Revolver. The borrowing base is subject to review and adjustment on a
semi-annual basis and other interim adjustments, including adjustments based
on
our hedging arrangements. Amounts outstanding under the revolver bear interest,
as amended, at specified margins over the London Interbank Offered Rate
(“LIBOR”) of 1.25% to 2.00%. Such margins will fluctuate based on the
utilization of the facility. Borrowings under the Revolver are collateralized
by
perfected first priority liens and security interests on substantially all
of
our assets, including a mortgage lien on oil and natural gas properties having
at least 80% of the PV-10 reserve value, a guaranty by all of
our
domestic subsidiaries, a pledge of 100% of the stock of domestic subsidiaries
and a lien on cash securing the Calpine gas purchase and sale contract. These
collateralized amounts under the mortgages are subject to semi-annual reviews
based on updated reserve information. We are subject to the financial covenants
of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each
fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0,
calculated at the end of each fiscal quarter for the four fiscal quarters
then
ended, measured quarterly with the pro forma effect of acquisitions and
divestitures. At September 30, 2006, our current ratio was 3.7 and our leverage
ratio was 1.3. In addition, we are subject to covenants limiting dividends
and
other restricted payments, transactions with affiliates, incurrence of debt,
changes of control, asset sales, and liens on properties. We were in compliance
with all covenants at September 30, 2006. All amounts drawn under the revolver
are due and payable on July 7, 2009. Availability under the revolving line
of credit was $159.0 million at September 30, 2006.
In
July
2006, we entered into a Deposit Account Control Agreement in order to provide
a
security interest under the terms of our senior secured revolving line of
credit. Under the terms of the Deposit Account Control Agreement, we were
required to maintain $15.0 million on account to keep a borrowing base of $325.0
million. Based on the semi-annual review of our borrowing base, a consent
agreement was signed in October 2006 in which the borrowing base remained at
$325.0 million and we were no longer required to maintain the $15.0 million
balance pursuant to the Deposit Account Control Agreement
Second
Lien Term Loan. BNP
Paribas, in July 2005, also provided us with a second lien term loan
concurrent with the acquisition, in the amount of $100.0 million. On
September 27, 2005, we repaid $25.0 million of borrowings on the term loan,
reducing the balance to $75.0 million and syndicated the loan to a group of
lenders including BNP Paribas. Borrowings under the term loan initially bore
interest at LIBOR plus 5.00%. As a result of the hedges put in place in July
2005 and the favorable effects of our private equity placement, as described
above, the interest rate for the second lien term loan has been reduced to
LIBOR
plus 4.00%. The loan is collateralized by second priority liens on substantially
all of our assets. We are subject to the financial covenants of a minimum asset
coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of
not
more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the
four
fiscal quarters then ended, measured quarterly with the pro forma effect of
acquisitions and divestitures. In addition, we are subject to covenants limiting
dividends and other restricted payments, transactions with affiliates,
incurrence of debt, changes of control, asset sales, and liens on properties.
We
were in compliance with all covenants at September 30, 2006. The revised
principal balance is due and payable on July 7, 2010.
Cash
Flows
|
|
Successor
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Nine
months ended September 30,
|
|
Three
months ended September 30,
|
|
|
Six
months ended June 30,
|
|
|
|
2006
|
|
2005
|
|
|
2005
|
|
(In
thousands)
|
|
|
Cash
flows provided by operating activities
|
|
$
|
141,621
|
|
$
|
63,250
|
|
|
$
|
59,379
|
|
Cash
flows used in investing activities
|
|
|
(162,161
|
)
|
|
(937,592
|
)
|
|
|
(30,645
|
)
|
Cash
flows provided by (used in) financing activities
|
|
|
(441
|
)
|
|
981,315
|
|
|
|
(27,239
|
)
|
Net
(decrease) increase in cash and cash equivalents
|
|
$
|
(20,981
|
)
|
$
|
106,973
|
|
|
$
|
1,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Activities.
Key
drivers of net cash provided by operating activities are commodity prices,
production volumes and costs and expenses, which primarily include operating
costs, taxes other than income taxes, transportation expense and administrative
expenses.
Net
cash
provided by operating activities for the nine months ended September 30, 2006
was $141.6 million generated from total production of 24.4 Bcfe with revenue
of
$199.1 million and net income before income tax of $50.7 million. Natural gas
averaged $7.84 per Mcf, including the effects of hedging and oil averaged $65.99
per Bbl during this period. Cash flows provided by operating activities were
primarily used to fund exploration and development expenditures.
Net
cash
provided from operations for the three months ended September 30, 2005 was
$63.3
million generated from total production of 7.1 Bcfe. Natural gas prices averaged
$8.03 per Mcf, including the effects of hedging, and oil averaged $60.03 per
Bbl
during this period.
Net
cash
provided from operations for the six months ended June 30, 2005 was $59.4
million generated from total production of 15.5 Bcfe with revenue of $103.8
million and net income of $30.2 million before tax. Natural gas prices averaged
$6.59 per Mcf and oil averaged $49.86 per Bbl during the quarter.
Investing
Activities.
The
primary driver of cash used in investing activities is capital
spending.
Cash
used
in investing activities for the nine months ended September 30, 2006 was $162.2
million and primarily related to the purchases of property and equipment with
additional capital expenditures accrued for at quarter end as well as the
restrictions placed on the cash balance of $15 million associated with the
Deposit Account Control Agreement
Cash
used
in investing activities for the three months ended September 30, 2005 was $937.6
million due to the acquisition of the domestic oil and natural gas business
of
Calpine in the amount of $910 million in total capital
expenditures.
Cash
used
in investing activities for the six months ended June 30, 2005 was $30.6 million
related to drilling and completion work and lease acquisitions less sale of
assets.
Financing
Activities.
The
primary driver of cash used in financing activities is equity transactions,
the
acquisition of new debt facilities or increase in intercompany notes payable
and
corresponding repayments of debt.
Net
cash
used in financing activities for the nine months ended September 30, 2006 was
$0.4 million and primarily related to the equity offering transaction fees,
proceeds from issuances of common stock and stock-compensation excess tax
benefit.
Net
cash
provided by financing activities for the three months ended September 30, 2005
was $981.3 million. This was due to $800 million in equity offering proceeds
net
of $54.0 million in transaction fees and $325 million in our senior credit
facility for the acquisition of the domestic oil and natural gas business of
Calpine and operating needs offset by repayment of $85.0 million of long-term
debt and $5.1 million of deferred loan costs.
Net
cash
used in financing activities for the six months ended June 30, 2005 was
comprised of repayments of notes to affiliates totaling $27.2
million.
Capital
Expenditures
Our
capital expenditures for the nine months ended September 30, 2006 were $151.0
million and we currently expect to expend approximately $40 million during
the
fourth quarter of 2006. These capital expenditures were primarily associated
with increased drilling activity in California and South Texas. We believe
we
have adequate expected cash flows from operations and available borrowings
under
our revolving credit facility to cover our budgeted capital expenditures.
We
are
currently exposed to market risk primarily related to adverse changes in oil
and
natural gas prices and interest rates. We use derivative instruments to manage
our commodity price risk caused by fluctuating prices. We do not enter into
derivative instruments for trading purposes. For information regarding our
exposure to certain market risks, see Item 7A. “Quantitative and Qualitative
Disclosure About Market Risks” in our annual report filed on Form 10-K for the
year ended December 31, 2005. There have been no significant changes in our
market risk from what was disclosed in the Form 10-K for the year ended December
31, 2005.
Under
the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of
the
effectiveness of the design and operation of our disclosure controls and
procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934, as amended (“Exchange Act”), as of September 30, 2006.
Disclosure controls and procedures are those controls and procedures designed
to
provide reasonable assurance that the information required to be disclosed
in
our Exchange Act filings is (1) recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission’s rules
and forms, and (2) accumulated and communicated to management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.
Based
on
that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that, as of September 30, 2006, our disclosure controls and procedures
were not effective, at the reasonable assurance level, due to the identification
of the material weaknesses in internal control over financial reporting
described below. Notwithstanding the material weaknesses described below, we
believe our unaudited consolidated financial statements included in this
quarterly filing on Form 10-Q fairly present in all material respects our
financial position, results of operations and cash flows for the periods
presented in accordance with generally accepted accounting principles as
applicable to interim reporting.
In
preparing our Exchange Act filings, including this quarterly filing on Form
10-Q, we implemented processes and procedures to provide reasonable assurance
that the identified material weaknesses in our internal control over financial
reporting were mitigated
with
respect to the information that we are required to disclose. As a result, we
believe, and our Chief Executive Officer and Chief Financial Officer have
certified to their knowledge, that this quarterly filing on Form 10-Q does
not
contain any untrue statements of material fact or omit to state any material
fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered in this report.
Material
Weaknesses in Internal Control Over Financial Reporting
A
material weakness is a control deficiency, or combination of control
deficiencies, that results in more than a remote likelihood that a material
misstatement of the annual or interim financial statements will not be prevented
or detected. We have identified various deficiencies in internal control over
financial reporting. We believe that many of these are attributable to our
transition from a subsidiary of a much larger company to a stand alone entity.
In connection with the preparation of our unaudited consolidated financial
statements and our assessment of the effectiveness of our disclosure controls
and procedures as of September 30, 2006 to be included in this Quarterly Report
on Form 10-Q to be filed under the Exchange Act, we identified the following
specific control deficiencies, which represent material weaknesses in our
internal control over financial reporting as of September 30, 2006:
|
a)
|
We
did not have a sufficient compliment of permanent personnel to have
an
appropriate accounting and financial reporting organizational structure
to
support the activities of the Company. Specifically, we did not have
permanent personnel with an appropriate level of accounting knowledge,
experience and training in the selection, application and implementation
of generally accepted accounting principles and financial reporting
commensurate with our financial reporting requirements;
and
|
|
b)
|
We
did not have effective controls as it relates to the identification
and
documentation of accounting policies, including selection and application
of generally accepted accounting principles used for accounting for
select
transactions and other activities. This deficiency resulted in a
reduced
ability to ensure the timely and accurate recording of certain
transactions and activities primarily relating to accounting for
derivatives and debt modifications. As a result, we did not have
sufficient procedures to ensure significant underlying select transactions
were appropriately and timely accounted for in the general
ledger.
|
In
addition, these material weaknesses could result in a misstatement of certain
accounts and disclosures which would result in a material misstatement of annual
or interim financial statements that would not be prevented or detected.
Accordingly, management has concluded that these control deficiencies constitute
material weaknesses. These material weaknesses also existed at December 31,
2005, March 31, 2006 and June 30, 2006.
Remediation
Activities
As
discussed above, management has identified certain material weaknesses that
exist in our internal control over financial reporting and management has taken
steps to strengthen our internal control over financial reporting. Since January
1, 2006, we employed additional accounting personnel and began improving our
documentation of our accounting policies and procedures. Specifically, we have
taken the following remedial actions:
|
1.
|
We
employed a certified public accountant from one of the top tier Accounting
Firms to be the manager of financial
reporting;
|
|
2.
|
We
employed a person to fill the position of manager of internal audit
to
review and audit our internal control environment and make recommendations
for improvement;
|
|
3.
|
We
have replaced our manager of fixed assets and accounts payable with
a more
highly credentialed person having a masters degree in business
administration who is also a certified public accountant and have
authorized the hiring of a senior fixed asset
accountant;
|
|
4.
|
We
employed a certified public accountant with specific expertise in
accounting software systems to evaluate and implement further enhancements
to our software and related procedures to improve our accounting
control;
|
|
5.
|
We
employed two supervisory level accountants who have extensive industry
experience; and
|
|
6. |
We have made substantial progress on the establishment
and documentation of our accounting policies and
procedures. |
These
measures already taken and those authorized but not yet taken to address the
material weaknesses identified, when fully implemented, are expected to provide
reasonable assurance that our internal control over financial reporting will
be
effective.
Beginning
with the year ending December 31, 2007, pursuant to Section 404 of the
Sarbanes-Oxley Act, we will be required to deliver a report that assesses the
effectiveness of our internal control over financial reporting, and our auditors
will be required to audit and report on our assessment of and the effectiveness
of our internal control over financial reporting. We are in the process of
completing the documentation and testing of our internal control over financial
reporting and remediating any additional material weaknesses identified during
that activity. Accordingly, we may not be able to complete the required
management assessment by our reporting deadline. An inability to complete this
assessment would result in receiving something other than an unqualified report
from our auditors with respect to our assessment of our internal control over
financial reporting. In addition, if material weaknesses are not remediated,
we
would not be able to conclude that our internal control over financial reporting
was effective, which would result in the inability of our external auditors
to
deliver an unqualified report on the effectiveness of our internal control
over
financial reporting.
OTHER
INFORMATION
We
and
our subsidiaries are party to various oil and natural gas litigation matters
arising out of the ordinary course of business. While the outcome of these
proceedings cannot be predicted with certainty, we do not expect these matters
to have a material adverse effect on the financial statements.
We
carry
insurance with coverage and coverage limits consistent with our assessment
of
risks in our business and of an acceptable level of financial exposure. Although
there can be no assurance that such insurance will be sufficient to mitigate
all
damages, claims or contingencies, we believe that our insurance provides
reasonable coverage for known asserted or unasserted claims. In the event we
sustain a loss from a claim and the insurance carrier disputed coverage or
coverage limits, we may record a charge in a different period than the recovery,
if any, from the insurance carrier.
Calpine
Bankruptcy
Calpine
Corporation and certain of its subsidiaries filed for protection under the
federal bankruptcy laws in the Court on December 20, 2005. Calpine Energy
Services, L.P., which filed for bankruptcy, has continued to make the required
deposits into the Company’s margin account and to timely pay for natural gas
production it purchases from the Company’s subsidiaries under various natural
gas supply agreements. As part of the Acquisition, we entered into a Transition
Services Agreement with Calpine, pursuant to which both parties were to provide
certain services for the other for various periods of time. Calpine’s obligation
to provide services under the Transition Services Agreement ceased on July
6,
2006 and certain of Calpine’s services ceased prior to the conclusion of the
contract, which in neither case had any material effect on us.
Additionally, Calpine Producer Services, L.P., which filed for bankruptcy,
generally is performing its obligations under the Marketing and Services
Agreement with us.
There
remains the possibility, however, that there will be issues between the us
and Calpine that could amount to material contingencies in relation to the
Purchase and Sale Agreement and interrelated agreements concurrently executed
therewith, dated July 7, 2005, by and among Calpine, the Company, and various
other signatories thereto (collectively, the “Purchase Agreement”), including
unasserted claims and assessments with respect to (i) the still pending Purchase
Agreement and the amounts that will be payable in connection therewith, (ii)
whether or not Calpine and its affiliated debtors will, in fact, perform their
remaining obligations in connection with the Purchase Agreement; and (iii)
the
ultimate disposition of the remaining Non-Consent Properties (and related
royalty revenues). Calpine has specific obligations to us under the Purchase
Agreement relating to these matters, and also has “further assurances” duties to
us under the Purchase Agreement.
In
addition, as to certain of the other oil and natural gas properties we purchased
from Calpine in the Acquisition and for which payment was made on July 7, 2005,
we will seek additional documentation from Calpine to eliminate any open issues
in our title or resolve any issues as to the clarity of our ownership. Requests
for additional documentation are customary in connection with transactions
similar to the Acquisition. In the Acquisition, certain of these properties
require ministerial governmental action approving us as qualified assignee
and
operator, which is typically required even though in most cases Calpine has
already conveyed the properties to us free and clear of mortgages and liens
in
favor of Calpine’s creditors. As to certain other properties, the documentation
delivered by Calpine at closing under the Purchase Agreement was incomplete.
We
remain hopeful that Calpine will continue to work cooperatively with us to
secure these ministerial governmental approvals and to accomplish the curative
corrections for all of these properties. In addition, as to all properties
acquired by us in the Acquisition, Calpine contractually agreed to provide
us
with such further assurances as we may reasonably request. Nevertheless, as
a
result of Calpine’s bankruptcy filing, it remains uncertain as to whether
Calpine will respond cooperatively. If Calpine does not fulfill its contractual
obligations and does not complete the documentation necessary to resolve these
issues, we will pursue all available remedies, including but not limited to
a
declaratory judgment to enforce our rights and actions to quiet title. After
pursuing these matters, if we experience a loss of ownership with respect to
these properties without receiving adequate consideration for any resulting
loss
to us, an outcome our management considers to be remote, then we could
experience losses which could have a material adverse effect on our financial
condition, statement of operations and cash flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Court seeking the entry of an order authorizing Calpine to
assume certain oil and natural gas leases Calpine has previously sold or
agreed to sell to us in the Acquisition, to the extent those leases constitute
“unexpired leases of non-residential real property” and were not fully
transferred to us at the time of Calpine’s filing for bankruptcy. According to
this motion, Calpine filed the motion in order to avoid the automatic forfeiture
of any interest it may have in these leases by operation of a statutory
deadline. Calpine’s motion did not request that the Court determine whether
these properties belong to us or Calpine, but we understand it was meant to
allow Calpine to preserve and avoid forfeiture under the Bankruptcy Code of
whatever interest Calpine may possess, if any, in these oil and natural gas
leases. We dispute Calpine’s contention that it may have an interest in any
significant portion of these oil and natural gas leases and intend to take
the necessary steps to protect all of our rights and interest in and to the
leases. On July 7, 2006, we filed an objection in response to Calpine’s motion,
wherein we asserted that oil and natural gas leases constitute interests in
real property that are not subject to “assumption” under the Bankruptcy Code. In
the objection we also requested that (a) the Court eliminate from the order
certain Federal offshore leases from the Calpine motion because these properties
were fully conveyed to us in July 2005, and the Minerals Management Service
has
subsequently recognized us as owner and operator of these properties, and (b)
any order entered by the Court be without prejudice to, and fully preserve
our
rights, claims and legal arguments regarding the characterization and ultimate
disposition of the remaining described oil and natural gas properties. In our
objection, we also urged the Court to require the parties to promptly address
and resolve any remaining issues under the pre-bankruptcy definitive agreements
with Calpine and proposed to the Court that the parties seek arbitration (or
at
least mediation) to complete the following:
|
·
|
Calpine’s
conveyance of the Non-Consent Properties to
us;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which we have
already paid Calpine; and
|
|
·
|
Resolution
of the final amounts we are to pay Calpine, which we have concluded
are
approximately $79 million, consisting of roughly $68 million for
the
Non-Consent Properties and approximately $11 million in other true-up
payment obligations.
|
At
a
hearing held on July 12, 2006, the Court in Calpine Corporation’s bankruptcy
took the following steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Minerals Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render our objection
inapplicable at that time; and
|
|
·
|
The
Court also encouraged Calpine and us to arrive at a business solution
to
all remaining issues including approximately $68 million payable
to
Calpine for conveyance of the Non-Consent Properties.
|
On
August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts and unliquidated damages in amounts that can
not
presently be determined. We
continue to work with Calpine on a cooperative and expedited basis toward
resolution of unresolved conveyance of properties and post-closing adjustments
under the Purchase Agreement.
By
a
proposed stipulation dated October 18, 2006, Calpine and the Department of
Justice agreed to further extend the deadline to assume or reject the MMS Oil
and Gas Leases under Section 365 of the Bankruptcy Code from November 15, 2006
to January 31, 2007, to the extent the MMS Oil and Gas Leases are “unexpired
leases” subject to Section 365. We have filed an objection to this proposed
stipulation requesting the Court condition its approval of the proposed
stipulation on inclusion of appropriate language adequately reserving our rights
with respect to the MMS Oil and Gas Leases and clarifying that the United States
Department of Interior will not take regulatory action with respect to such
leases without first seeking relief from the Court. On November 1, 2006, Calpine
and the State of California submitted a similar proposed stipulation extending
the deadline to assume or reject the CSLC Leases until January 31, 2007. We
will
take all necessary action to ensure our rights under the CSLC Leases are fully
protected.
We
continue to believe that it is unlikely that any challenges by the Calpine
debtors or their creditors to the fairness of the Acquisition would be
successful. However, there can be no assurance that Calpine, its creditors
or
interest holders may not challenge the fairness of some or all of the
Acquisition. For a number of reasons, including our understanding of the process
that Calpine followed in allowing market forces to set the purchase price for
the Acquisition, we believe that it is unlikely that any challenge to the
fairness of the Acquisition would be successful.
Other
than
with
respect to the risk factors below, there have been no material changes in our
risk factors from those disclosed in Item 1A of our Annual Report on Form 10-K
for the year ended December 31, 2005. The
following risk factors were disclosed on the Form 10-K and have been updated
as
of September 30, 2006.
Calpine’s
recent bankruptcy filing may adversely affect us in several
respects.
Calpine,
its creditors and interest holders may challenge the fairness of some or all
of
the Acquisition.
Calpine
and certain of its subsidiaries (the “Debtors”) filed for protection under the
federal bankruptcy laws in the Court on December 20, 2005 (the “Petition
Date”). Calpine, its creditors or interest holders may bring an action under the
Bankruptcy Code or relevant state fraudulent conveyance laws asserting that
Calpine’s transfer of its domestic oil and natural gas business to us (as either
the initial transferee or the immediate or mediate transferee from the initial
transferee) should be voided or set aside as a fraudulent transfer. To prevail
in such a legal action, Calpine, its creditors or interest holders would be
required to prove that Calpine either:
|
·
|
Transferred
its domestic oil and natural gas business to us with the intent of
hindering, delaying or defrauding its current or future creditors;
or
|
|
·
|
As
of July 7, 2005 (the date of the closing of the Acquisition),
(a) received less than reasonably equivalent value for the business,
and (b) was insolvent, became insolvent as a result of such transfer,
was engaged in a business or transaction or was about to engage in
a
business or transaction for which any property remaining was unreasonably
small, or intended to incur or believed it would incur debts that
would be
beyond its ability to pay as such debts matured.
|
Our
primary defense against such a legal challenge rests on the extensive
negotiations leading up to, and the market pricing mechanisms incorporated
within the terms of the Acquisition. Nonetheless, if after a trial on the
merits, the Court was to determine that the Debtors have met their burden of
proof, it could void the transfer or take other actions against us, including
(i) setting aside the Acquisition and returning our purchase price and give
us a
first lien on all the properties and assets we purchased in the acquisition
or
(ii) sustaining the Acquisition subject to our being required to pay the
Debtors the amount, if any, by which the fair value of the business transferred,
as determined by the Court as of July 7, 2005, exceeded the purchase price
determined and paid in July 2005. If the Court should so rule, a setting aside
of the Acquisition would be materially detrimental to us in that substantially
all our properties would be returned to Calpine, subject to our right (as a
good
faith transferee) to retain a lien in our favor to secure the return of the
purchase price we paid for the properties. Additionally, if the Court should
so
rule, any requirement to pay an increased purchase price could adversely affect
us depending on the amount we might be required to pay.
The
bankruptcy proceeding may prevent, frustrate or delay our ability to receive
record legal title to certain properties originally determined to be Non-Consent
Properties which we are entitled to receive under the Purchase
Agreement.
At
the
closing of the Acquisition, Calpine agreed to sell but retained title to certain
domestic oil and natural gas properties, subject to obtaining various third
party consents or waivers of preferential purchase rights in order to effect
transfer of title. In July 2005, as part of the transactions undertaken in
connection with closing the Acquisition, we accepted possession of and have
since been operating all of the properties for which Calpine retained record
legal title. We withheld approximately $75 million from the aggregate purchase
price, which was the allocated dollar amount under the Purchase Agreement for
the remaining properties. Subsequent to the closing of the Acquisition, with
the
exception of the properties subject to the preferential right to purchase,
we
obtained substantially all of the consents to assign for all of these remaining
properties for which consents were actually required. Prior to the Calpine
bankruptcy, we were prepared to consummate the assignments of these remaining
properties, except those subject to the preferential purchase right to purchase.
The PV-10 value of these properties at December 31, 2005 was approximately
$72.4 million. Based on our internal calculations, we estimate the PV-10 value
of these properties at current market prices to be approximately $61.7 million.
We are prepared to pay Calpine the retained portion of the original purchase
price, approximately $68 million, and approximately $11 million in other true-up
payment obligations, all upon our receipt from Calpine of record title, free
of
any encumbrance, for that portion of these properties which are the Non-Consent
Properties, subject to appropriate adjustment for the net revenues and expenses
through December 15, 2005. If the assignment of any remaining properties
(including any leases) does not occur, the portion of the purchase price we
held
back pending consent or waiver will be retained by us and will be available
to
us for general corporate purposes.
The
bankruptcy proceeding may prevent, frustrate or delay our ability to receive
corrective documentation from Calpine for certain properties that we bought
from
Calpine and paid for, in cases where Calpine delivered incomplete documentation,
including documentation related to certain ministerial governmental
approvals.
Certain
of the properties we purchased from Calpine and paid Calpine for on July 7,
2005, require certain additional documentation, depending on the particular
facts and circumstances surrounding the particular properties involved, such
documentation to be delivered by Calpine to quiet title related to our ownership
of these properties. Certain of these properties are subject to ministerial
governmental action approving us as qualified assignee and operator, even though
in most cases there had been a conveyance by Calpine and release of mortgages
and liens by Calpine’s creditors. For certain other properties, the
documentation delivered by Calpine at closing was incomplete. While we remain
hopeful that Calpine will continue to work cooperatively with us to
secure these ministerial governmental approvals and accomplish the curative
corrections for all of these properties for which we paid Calpine for, all
of
the same being covered, we believe, by the further assurances provision of
the
Purchase Agreement, the exact details for each property involved and how, when
and if this will be able to be secured or accomplished continue to remain
uncertain at this stage of Calpine’s bankruptcy.
Additionally,
on June 29, 2006, Calpine filed a motion in connection with its pending
bankruptcy proceeding seeking entry of an order authorizing Calpine to assume
certain oil and natural gas leases which Calpine previously sold or agreed
to
sell to us in the acquisition, to the extent those leases constitute “unexpired
leases of non-residential real property” and were not fully transferred to us at
the time of Calpine’s filing for bankruptcy. According to this motion, Calpine
filed it to avoid the automatic forfeiture of any interest it might have in
these leases by operation of a statutory deadline. Calpine’s motion did not
request that the Court determine whether these properties belong to us or to
Calpine. Generally, oil and gas leases are regarded as real property and not
leases of real property despite their being called leases. If Calpine
successfully convinces the Court that the oil and natural gas leases are
“unexpired leases of non-residential real property,” subject to its obligations
under the Purchase Agreement, Calpine could require that we take further action
or pay further consideration to complete the assignments of these interests
or
could retain the leases.
Any
failure to complete the corrective action necessary to remove title deficiencies
with respect to certain of these properties, including failure by Calpine to
deliver corrective documentation or failure of the Court to require Calpine
to
deliver such corrective documentation, could result in a material adverse effect
on us if we are not able to receive any offsetting refund of the portion of
the
purchase price attributable to the properties or if we are required to pay
additional consideration.
We
have expended and may continue to expend significant resources in connection
with Calpine’s bankruptcy.
We
have
expended and may continue to expend significant resources in connection with
Calpine’s bankruptcy. These resources include our increased costs for lawyers,
consultant experts and related expenses, as well as lost opportunity costs
associated with our dedicating internal resources to these matters. If we
continue to expend significant resources and our management is distracted from
the operational matters by the Calpine bankruptcy, our business, results of
operations, financial position or cash flows could be adversely
affected.
Operating
hazards, natural disasters or other interruptions of our operations could result
in potential liabilities, which may not be fully covered by our
insurance.
The
oil
and natural gas business involves certain operating hazards such
as:
|
·
|
Uncontrollable
flows of oil, natural gas or well
fluids;
|
|
·
|
Hurricanes,
tropical storms, earthquakes, mud slides, and
flooding;
|
The
occurrence of one of the above may result in injury, loss of life, suspension
of
operations, environmental damage and remediation and/or governmental
investigations and penalties.
In
addition, our operations in California are especially susceptible to damage
from
natural disasters such as earthquakes and fires and involve increased risks
of
personal injury, property damage and marketing interruptions. Any of these
operating hazards could cause serious injuries, fatalities or property damage,
which could expose us to liabilities. The payment of any of these liabilities
could reduce, or even eliminate, the funds available for exploration,
development, and acquisition, or could result in a loss of our properties.
Our
insurance policies provide limited coverage for losses or liabilities relating
to pollution, with broader coverage for sudden and accidental occurrences.
Our
insurance might be inadequate to cover our liabilities. For example, we are
not
fully insured against earthquake risk in California because of high premium
costs. Insurance covering earthquakes or other risks may not be available at
premium levels that justify its purchase in the future, if at all. In addition,
we are subject to energy package insurance coverage limitations related to
any
single named windstorm. The insurance market in general and the energy insurance
market in particular have been difficult markets over the past several years.
Insurance costs are expected to continue to increase over the next few years
and
we may decrease coverage and retain more risk to mitigate future cost increases.
If we incur substantial liability and the damages are not covered by insurance
or are in excess of policy limits, or if we incur liability at a time when
we
are not able to obtain liability insurance, then our business, results of
operations, financial condition, and cash flows could be materially adversely
affected. Because of the expense of the associated premiums and the perception
of risk, we do not have any insurance coverage for any loss of production as
may
be associated with these operating hazards.
Environmental,
health, and safety liabilities could adversely affect our financial
condition.
The
oil
and natural gas business is subject to environmental, health and safety hazards,
such as oil spills, natural gas leaks and ruptures and discharges of petroleum
products and hazardous substances, and historic disposal activities. These
hazards could expose us to material liabilities for property damages, personal
injuries or other environmental, health and safety harms, including costs of
investigating and remediating contaminated properties. In addition, we also
may
be liable for environmental damages caused by the previous owners or operators
of properties we have purchased or are currently operating. A variety of
stringent federal, state and local laws and regulations govern the environmental
aspects of our business and impose strict requirements for, among other
things:
|
·
|
Well
drilling or workover, operation and
abandonment;
|
|
·
|
Financial
assurance under the Oil Pollution Act of 1990;
and
|
|
·
|
Controlling
air, water and waste emissions.
|
Any
noncompliance with these laws and regulations could subject us to material
administrative, civil or criminal penalties or other liabilities. Additionally,
our compliance with these laws may, from time to time, result in increased
costs
to our operations or decreased production, and may affect our costs of
acquisitions. We are unable to predict the ultimate cost of complying with
these
regulations.
In
addition, environmental laws may, in the future, cause a decrease in our
production or cause an increase in our costs of production, development or
exploration. Pollution and similar environmental risks generally are not fully
insurable.
Some
of
our California properties have been in operation for a substantial length of
time, and current or future local, state and federal environmental and other
laws and regulations may require substantial expenditures to remediate the
properties or to otherwise comply with these laws and regulations. A variety
of
existing laws, rules and guidelines govern activities that can be conducted
on
our properties and other existing or future laws, rules and guidelines could
prohibit or limit our operations and our planned activities for
properties.
Under
our
Purchase Agreement with Calpine, we are responsible for environmental claims
prior to the acquisition and we have no indemnification from Calpine related
to
those claims.
Item
2.
Unregistered Sales of Equity Securities and Use of
Proceeds
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers
Period
|
|
Total
Number of Shares Purchased (1)
|
|
Average
Price Paid per Share
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans
or
Programs
|
|
Maximum
Number (or Approximate Dollar Value) of Shares that May yet Be
Purchased
Under the Plans or Programs
|
|
July
1 - July 31
|
|
|
14,169
|
|
$
|
16.22
|
|
|
-
|
|
|
-
|
|
August
1 - August 31
|
|
|
1,532
|
|
|
17.11
|
|
|
-
|
|
|
-
|
|
September
1 - September 30
|
|
|
1,349
|
|
|
17.50
|
|
|
-
|
|
|
-
|
|
(1)
|
All
of the shares repurchased were surrendered by employees to pay tax
withholding upon the vesting of restricted stock awards. These repurchases
were not part of a publicly announced program to repurchase shares
of our
common stock, nor do we have a publicly announced program to repurchase
shares of our common stock.
|
Issuance
of Unregistered Securities
None.
Item
3. Defaults
Upon Senior Securities
None.
Item
4. Submission
of Matters to a Vote of Security Holders
None.
Rosetta
reported on Form 8-K during the quarter covered by this report all information
required to be reported on such form.
31.1 Certification
of Periodic Financial Reports by B.A. Berilgen in satisfaction of Section 302
of
the Sarbanes-Oxley Act of 2002
31.2 Certification
of Periodic Financial Reports by Michael J. Rosinski in satisfaction of Section
302 of the Sarbanes-Oxley Act of 2002
32.1 Certification
of Periodic Financial Reports by B.A. Berilgen and Michael J. Rosinski in
satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C.
Section 1350
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. |
|
|
|
Date: November
14, 2006 |
By: |
/s/ Michael
J.
Rosinski |
|
Michael J. Rosinski |
|
Executive Vice President and Chief Financial Officer |
|
(Duly
Authorized Officer and Principal Financial
Officer) |
ROSETTA
RESOURCES INC.
Exhibit
Number
|
|
Description
|
31.1
|
|
Certification
of Periodic Financial Reports by B. A. Berilgen in satisfaction
of Section
302 of the Sarbanes-Oxley Act of 2002
|
31.2
|
|
Certification
of Periodic Financial Reports by Michael J. Rosinski in satisfaction
of
Section 302 of the Sarbanes-Oxley Act of 2002
|
32.1
|
|
Certification
of Periodic Financial Reports by B. A. Berilgen and Michael J.
Rosinski in
satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and
18
U.S.C. Section 1350
|