Filed
pursuant to Rule 424(b)(3)
Registration
Number 333-128888
PROSPECTUS
SUPPLEMENT NO. 3
(To
the Prospectus dated June 14, 2006)
50,000,000
Shares of
Common
Stock
____________________
This
Prospectus Supplement No. 3 supplements the prospectus dated June 14, 2006
and the Prospectus Supplements No. 1 and No. 2 dated August 15, 2006 and
November 14, 2006, respectively, (together, the "Prospectus"), relating to
the
sale by the holders of Common Stock of Rosetta Resources Inc. This prospectus
supplement should be read in conjunction with the Prospectus which is to be
delivered with this prospectus supplement. If there is any inconsistency between
the information in the Prospectus and this prospectus supplement, you should
rely on the information in this prospectus supplement.
INVESTING
IN OUR COMMON STOCK INVOLVES RISK. SEE "RISK FACTORS" BEGINNING ON PAGE 17
OF
OUR ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2005 AND ON
PAGE
10 OF THE PROSPECTUS.
This
prospectus supplement is filed for the purposes of including the information
contained in our amendment to our quarterly report on Form 10-Q/A for the
quarter ended September 30, 2006, which was filed with the Securities and
Exchange Commission on November 30, 2006.
______________________
NEITHER
THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION
HAS
APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ADEQUACY OR
ACCURACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
OFFENSE.
_____________________
The
date
of this Prospectus Supplement is November 30, 2006.
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Amendment
No. 1 to Form 10-Q on
FORM
10-Q/A
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
o
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 o
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 o
|
Accelerated
filer o
|
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 o 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.
Explanatory
Note
Rosetta
Resources, Inc. (the “Company”) is filing this Amendment No. 1 to its Quarterly
Report on Form 10-Q for the quarterly period ended September 30, 2006 (the
“Original Filing”), which was originally filed with the Securities and Exchange
Commission (“SEC”) on November 14, 2006. The purpose of this filing is to
clarify a typographical error of a certain number figure in the
Company’s Original Filing. In Part I - Item 2 Management’s Discussion
and
Analysis of Financial Condition and Results of Operations, in the Critical
Accounting Policies and Estimates, the ceiling test writedown which would
have
been charged to earnings had hedge adjusted market prices at September
30, 2006
been used was incorrectly reported as $182.1 million. The correct amount
should
have been $142.1 million consistent with the amount reported in Note 5
of the
notes to the Consolidated/Combined Financial Statements included in the
Original
Filing.
Additionally,
in connection with the filing of Amendment No. 1 and pursuant to SEC rules,
the Company is including as Exhibits to this Amendment No. 1 certain
certifications as of the date of this Amendment No. 1. Except as described
herein, this Amendment No. 1 does not amend any other disclosure in the
Original Filing as originally filed and does not reflect events occurring
after
the Original Filing. The Company hereby replaces all of Part I - Item 2
Management’s Discussion and Analysis of Financial Condition and Results of
Operations in the Original Filing with Item 2 set forth in this Amendment
No.
1.
1
Part
I. Financial Information
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;
|
2
|
·
|
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
3
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.
4
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 $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, 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
5
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.
6
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.
Operating
Expenses
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
|
7
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
8
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.
9
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.
10
Part
II.
Other Information
Item
6. Exhibits
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
11
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant
has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
|
|
Rosetta
Resources Inc.
|
|
|
|
|
|
Date: November
30, 2006
|
By:
|
/s/ Michael
J. Rosinski
|
| Michael J. Rosinski | ||
|
|
Executive
Vice President and Chief Financial Officer
|
|
|
|
(Duly
Authorized Officer and Principal Financial
Officer)
|
|
12
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
|
13